UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2012.2013. |
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| Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to �� . |
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Commission File Number |
| Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number | |
| IRS Employer Identification No. |
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| 1-14756 |
| Ameren Corporation | |
| 43-1723446 |
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| (Missouri Corporation) | |
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| 1901 Chouteau Avenue | |
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| St. Louis, Missouri 63103 | |
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| (314) 621-3222 | |
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| 1-2967 |
| Union Electric Company | |
| 43-0559760 |
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| (Missouri Corporation) | |
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| 1901 Chouteau Avenue | |
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| St. Louis, Missouri 63103 | |
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| (314) 621-3222 | |
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| 1-3672 |
| Ameren Illinois Company | |
| 37-0211380 |
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| (Illinois Corporation) | |
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| 6 Executive Drive | |
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| Collinsville, Illinois 62234 | |
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| (618) 343-8039343-8150 | |
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Securities Registered Pursuant to Section 12(b) of the Act:
The following security is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:
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| Registrant | | Title of each class | |
| Ameren Corporation | Common Stock, $0.01 par value per share |
Securities Registered Pursuant to Section 12(g) of the Act:
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| Registrant | | Title of each class | |
| Union Electric Company | Preferred Stock, cumulative, no par value, stated value $100 per share |
| Ameren Illinois Company | Preferred Stock, cumulative, $100 par value per share DepositoryDepositary Shares, each representing one-fourth of a share of 6.625% Preferred Stock, cumulative, $100 par value per share |
Indicate by checkmark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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| Ameren Corporation | Yes | (X) | No | ( ) |
| Union Electric Company | Yes | ( ) | No | (X) |
| Ameren Illinois Company | Yes | ( ) | No | (X) |
Indicate by checkmark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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| Ameren Corporation | Yes | ( ) | No | (X) |
| Union Electric Company | Yes | ( ) | No | (X) |
| Ameren Illinois Company | Yes | ( ) | No | (X) |
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.
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| Ameren Corporation | Yes | (X) | No | ( ) |
| Union Electric Company | Yes | (X) | No | ( ) |
| Ameren Illinois Company | Yes | (X) | No | ( ) |
Indicate by checkmark whether each registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
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| Ameren Corporation | Yes | (X) | No | ( ) |
| Union Electric Company | Yes | (X) | No | ( ) |
| Ameren Illinois Company | Yes | (X) | No | ( ) |
Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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.
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| Ameren Corporation |
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| Union Electric Company |
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| Ameren Illinois Company |
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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 Exchange Act.
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| Large Accelerated Filer |
| Accelerated Filer |
| Non-accelerated Filer |
| Smaller Reporting Company |
| Ameren Corporation |
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| Union Electric Company |
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| Ameren Illinois Company |
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Indicate by checkmark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act).
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| Ameren Corporation | Yes | ( ) | No | (X) |
| Union Electric Company | Yes | ( ) | No | (X) |
| Ameren Illinois Company | Yes | ( ) | No | (X) |
As of June 29,28, 20122013, Ameren Corporation had 242,634,671 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 the common stock on the New York Stock Exchange on June 29, 2012)28, 2013) held by nonaffiliates was $8,137,966,865.$8,356,338,069. The shares of common stock of the other registrants were held by Ameren Corporation as of June 29,28, 20122013.
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 20132014, was as follows:
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| Ameren Corporation | Common stock, $0.01 par value per share: 242,634,671 |
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| Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): 102,123,834 |
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| Ameren Illinois Company | Common stock, no par value, held by Ameren Corporation (parent company of the registrant): 25,452,373 |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company and Ameren Illinois Company for the 20132014 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
This combined Form 10-K is separately filed by Ameren Corporation, Union Electric Company, and Ameren Illinois 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.
TABLE OF CONTENTS
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| PART I | | |
| Item 1. | | |
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| Item 1A. | | |
| Item 1B. | | |
| Item 2. | | |
| Item 3. | | |
| Item 4. | | |
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| PART II | | |
| Item 5. | | |
| Item 6. | | |
| Item 7. | | |
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| Item 7A. | | |
| Item 8. | | |
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| Item 9. | | |
| Item 9A. | | |
| Item 9B. | | |
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| PART III | | |
| Item 10. | | |
| Item 11. | | |
| Item 12. | | |
| Item 13. | | |
| Item 14. | | |
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| PART IV | | |
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This report 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 4 and 5 of this report 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.Ameren Missouri, and Ameren Illinois, collectively. When appropriate, subsidiaries of Ameren Corporation are named specifically as we discuss their various business activities.activities are discussed.
2007 Illinois Electric Settlement Agreement - A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates. The settlement, which became effective in 2007, was designed to avoid rate rollback and freeze legislation and legislation that would have imposed a tax on electric generation in Illinois. The settlement addressed the issue of power procurement.
2010 Credit Agreements - The 2010 Genco Credit Agreement, the 2010 Illinois Credit Agreement, and the 2010 Missouri Credit Agreement, collectively, which terminated on November 14, 2012.
2010 Genco Credit Agreement - Ameren’s and Genco’s $500 million multiyear senior unsecured credit agreement, which was terminated on November 14, 2012.
2010 Illinois Credit Agreement - Ameren’s and Ameren Illinois’ $800 million multiyear senior unsecured credit agreement, which was terminated on November 14, 2012.
2010 Missouri Credit Agreement - Ameren’s and Ameren Missouri’s $800 million multiyear senior unsecured credit agreement, which was terminated on November 14, 2012.
2012 Credit Agreements - The 2012 Illinois Credit Agreement and the 2012 Missouri Credit Agreement, collectively.
2012 Illinois Credit Agreement - Ameren's and Ameren Illinois' $1.1 billion multiyear senior unsecured credit agreement, which expires on November 14, 2017.
2012 Missouri Credit Agreement - Ameren's and Ameren Missouri's $1 billion multiyear senior unsecured credit agreement, which expires on November 14, 2017.
AER - AmerenEnergyAmeren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consistsconsisted of non-rate-regulated operations,operations. On December 2, 2013, AER contributed substantially all of its assets and liabilities, including its ownership interests in Genco, AERG, and Marketing Company, and Medina Valley. Theto New AER. Medina Valley energy center was sold in February 2012. On October 1, 2010, AERG stock was distributed from AER to Ameren which then contributed it to AER, thereby making AERG a subsidiary of AER.on March 14, 2013.
AERG - Ameren Energy Resources Generating Company, a CILCOformer AER subsidiary until October 1, 2010, that operatesoperated a merchant electric generation business in Illinois. On October 1, 2010,December 2, 2013, AERG stock was distributedincluded in the divestiture of New AER to Ameren and subsequently contributed by Ameren toIPH. After the divestiture of New AER which resulted inwas completed, AERG becoming a subsidiary of AER.
AFS - Ameren Energy Fuels and Services Company, an AER subsidiary that procured fuel and natural gas and managed the related risks for the Ameren Companies prior to January 1, 2011. Effective January 1, 2011, the functions previously performed by AFS were assumed by the Ameren Missouri, Amerenbecame Illinois and Merchant Generation business segments.Power Resources Generating, LLC.
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 - Ameren Corporation, Ameren Missouri, and Ameren Illinois, collectively, which are individual registrants within the Ameren consolidated group.
Ameren Illinois or AIC - Ameren Illinois Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois, doing business as Ameren 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 Ameren Illinois Merger. References to Ameren Illinois prior to the Ameren Illinois Merger refer collectively to the rate-regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO and IP. Immediately after the Ameren Illinois Merger, Ameren Illinois distributed the common stock of AERG to Ameren Corporation. AERG’s operating results and cash flows prior to October 1, 2010, were presented as discontinued operations in Ameren Illinois’ financial statements. Ameren Illinois is also defined as a financial reporting segment beginning after 2010.segment.
Ameren Illinois Merger - On October 1, 2010, CILCO and IP merged with and into CIPS, with the surviving corporation renamed Ameren Illinois Company.
Ameren Illinois Segment - A financial reporting segment consisting of Ameren Illinois’ rate-regulated businesses.
Ameren Missouri or AMO - 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 Ameren Missouri. Ameren Missouri is also defined as a financial reporting segment.
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 Ameren Illinois and the Merchant Generation energy centers (excluding EEI and Elgin CT energy centers).ATXI.
AMMO - The MISO balancing authority area operated by Ameren, which includes the load and generation energy centers of Ameren
Missouri.
ARO - Asset retirement obligations.
ATXI - Ameren Transmission Company of Illinois, an Ameren Corporation subsidiary that is engaged in the construction and operation of electric transmission assets.
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 energy center's capacity was used during a specific period.
CCR - Coal combustion residuals.
CILCO - Central Illinois Light Company, a former Ameren Corporation subsidiary that operated a rate-regulated electric transmission and distribution business, a merchant electric
generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, before the Ameren Illinois Merger. CILCO owned all of the common stock of AERG and included AERG within its consolidated financial statements. Immediately after the Ameren Illinois Merger in 2010, Ameren Illinois distributed the common stock of AERG to Ameren Corporation. AERG's operating results and cash flows prior to October 1, 2010, were presented as discontinued operations in Ameren Illinois’ financial statements.
CILCORP - CILCORP Inc., a former Ameren Corporation subsidiary that operated as a holding company for CILCO and its merchant generation subsidiary. On March 4, 2010, CILCORP merged with and into Ameren.
CIPS - Central Illinois Public Service Company, an Ameren Corporation subsidiary, renamed Ameren Illinois Company at the effective date of the Ameren Illinois Merger, which operates a rate-regulated electric and natural gas transmission and distribution business, all in Illinois.
CO2 - Carbon dioxide.
COL - Nuclear energy center combined construction and operating license.
Cole County Circuit Court - Circuit Court of Cole County, Missouri.
Cooling degree-days - The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is useful as an indicator of electricity demand by residential and commercial customers for summer cooling.
CSAPR - Cross-State Air Pollution Rule.
CT - Combustion turbine electric energy center used primarily for peaking capacity.
DOE - Department of Energy, a United States government agency.
DRPlus - Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
Dekatherm - One million Btus of natural gas.
Dynegy - Dynegy Inc.
EEI - Electric Energy, Inc., an 80%-owned Genco subsidiary that operates merchant electric generation energy centers and FERC-regulated transmission facilities in Illinois. The remaining 20%On December 2, 2013, Genco's ownership interest is owned by Kentucky Utilities Company, a nonaffiliated entity.in EEI was included in the divestiture of New AER to IPH.
Entergy -Entergy Arkansas, Inc.
EPA - Environmental Protection Agency, a United States
government agency.
Equivalent availability factor - A measure that indicates the percentage of time an energy center was available for service during a period.
ERISA - Employee Retirement Income Security Act of 1974, as amended.
Exchange Act - Securities Exchange Act of 1934, as amended.
FAC - AFuel adjustment clause, a fuel and purchased power cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in net energy costs greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews. Net energy cost includes fuel (coal, coal transportation, natural gas for generation, and nuclear), certain fuel additives, emission allowances, purchased power costs, transmission costs and revenues, and MISO costs and revenues, net of off-system revenues, greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudency reviews. The MoPSC's December 2012 electric rate order changed the FAC to include activated carbon, limestone and urea costs, along withsales revenues.
transmission revenues, starting in 2013.
FASB - Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.
FERC - Federal Energy Regulatory Commission, a United States government agency.
Fitch - Fitch Ratings, a credit rating agency.
FTRs - Financial transmission rights, financial instruments that entitlespecify whether the holder toshall pay or receive compensation for certain congestion-related transmission charges between two designated points.
Fuelco - Fuelco LLC, a limited liability company that provides nuclear fuel management and services to its members. The members are Ameren Missouri, Luminant, and Pacific Gas and Electric Company.
GAAP - Generally accepted accounting principles in the United States of America.
Genco - Ameren Energy Generating Company, ana former AER subsidiary that operatesoperated a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI. On December 2, 2013, Genco was included in the divestiture of New AER to IPH. After the New AER divestiture was completed, Genco became Illinois Power Generating Company.
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 by 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 Ameren Illinois and ATXI.
IEIMA - Illinois Energy Infrastructure Modernization Act, an Illinois law that established a performance-based formula process for determining electric delivery service rates. Ameren Illinois electedBy its election to participate in this regulatory framework, in 2012, which will require itAmeren Illinois is required to make incremental capital expenditures to modernize its electric distribution system, over a ten-year period, to meet performance standards, and to create jobs in Illinois, among other things.
Illinois Customer Choice Law - Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which was designed to introduce competition into the retail supply of electric energy in Illinois.
IP - Illinois Power Company, a former Ameren Corporation subsidiary that operated a rate-regulated electric and natural gas transmission and distribution business, all in Illinois, before the Ameren Illinois Merger.
IPA - Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and small commercial customers.
IPH - Illinois Power Holdings, LLC, an indirect wholly owned subsidiary of Dynegy.
IRS - Internal Revenue Service, a United States government agency.
ISRS - Infrastructure system replacement surcharge, which is a cost recovery mechanism that allows Ameren Missouri to recover natural gas infrastructure replacement costs from utility customers without a traditional rate proceeding.
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 one hour.
LIUNA - Laborers’ International Union of North America, a labor union.
Marketing Company - Ameren Energy Marketing Company, ana former AER subsidiary that marketsmarketed power for Genco, AERG, and EEI. Marketing Company was included in the divestiture of New AER to IPH on December 2, 2013. After the divestiture of New AER was completed, Marketing Company became Illinois Power Marketing Company.
MATS - Mercury and Air Toxics Standards.
Medina Valley - Ameren EnergyAmerenEnergy Medina Valley Cogen, LLC, an AER subsidiary, whichAmeren Corporation subsidiary. Previously, this company owned a 40-megawatt natural gas-fired electric energy center. This energy center that was sold in February 2012. This company was distributed from AER to Ameren on March 14, 2013.
MEEIA --- Missouri Energy Efficiency Investment Act, a Missouri law that allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs.
Megawatthour or MWh - One thousand kilowatthours.
Merchant Generation - A financial reporting segment consistingthat prior to the divestiture of New AER to IPH on December 2, 2013, consisted primarily of the operations of AER, including Genco, AERG, Marketing Company and, through March 13, 2013, Medina Valley and Marketing Company.Valley.
MGP - Manufactured gas plant.
MIEC - Missouri Industrial Energy Consumers.
MISO - MidwestMidcontinent Independent Transmission System Operator, Inc., an RTO.
MISO Energy and Operating Reserves Market - A market that uses market-based pricing, which 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.
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 businesses 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.
MoOPC - Missouri Office of Public Counsel.
MoPSC - Missouri Public Service Commission, a state agency that regulates Missouri utility businesses, including Ameren Missouri.
MPS - Multi-Pollutant Standard, a compliance alternative withinunder Illinois law covering reductions in emissions of SO2, NOx, and mercury, which Genco, EEI, and AERG elected in 2006.
MTM - Mark-to-market.
MW - Megawatt.
Native load - End-use retail customers whom we are obligated to serve by statute, franchise, contract, or other regulatory requirement.
NERC - North American Electric Reliability Corporation.
New AER - New Ameren Energy Resources Generating Company, LLC, a limited liability company formed as a direct wholly owned subsidiary of AER. New AER, acquired by IPH on December 2, 2013, included substantially all of the assets and liabilities of AER, except for certain assets and liabilities retained by Ameren. After Ameren's divestiture of New AER to IPH was completed, this entity became Illinois Power Resources, LLC.
NO2 - Nitrogen dioxide.
NOx - Nitrogen oxide.oxides.
Noranda - Noranda Aluminum, Inc.
NPNS - Normal purchases and normal sales.
NRC - Nuclear Regulatory Commission, a United States government agency.
NSPS - New Source Performance Standards, a provision under the Clean Air Act.
NSR - New Source Review provisions of the Clean Air Act, which include Nonattainment New Source Review and Prevention of Significant Deterioration regulations.
NWPA - Nuclear Waste Policy Act of 1982, as amended.
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 sales revenues - Revenues from other than native load sales, including wholesale sales beginning with the July 31, 2011 effective date of the MoPSC’s 2011 electric rate order.
OTC - Over-the-counter.
PGA - Purchased Gas Adjustment tariffs, which permit prudently incurred natural gas costs to be recovered directly from utility customers without a traditional rate proceeding.
PJM - PJM Interconnection LLC.
PUHCA 2005 - The Public Utility Holding Company Act of 2005.
Rate base - The net value of property on which a public utility is permitted to earn an allowed rate of return.
Regulatory lag - The effect of adjustments to retail electric and natural gas rates being based on historic cost and revenuesales volume levels. Rate increase requests, in traditional rate case proceedings, 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 revenuessales volume levels when based on historical periods.
Revenue requirement - The cost of providing utility service to customers, which is calculated as the sum of a utility's recoverable operating and maintenance expenses, depreciation and amortization expense, taxes, and an allowed return on investment.
RFP - Request for proposal.
Rockland Capital - Rockland Capital, LLC together with the special purpose entity affiliated with and formed by Rockland Capital, LLC that acquired the Elgin, Gibson City, and Grand Tower gas-fired energy centers.
RTO - Regional Transmission Organization.transmission organization.
S&P - Standard & Poor’s Ratings Services, a credit rating agency.
SEC - Securities and Exchange Commission, a United States 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.
Stoddard County Circuit Court - Circuit Court of Stoddard County, Missouri.
UA - United Association of Plumbers and Pipefitters, a labor union.
Westinghouse - Westinghouse Electric Company.
FORWARD-LOOKING STATEMENTS
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:
regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the complaint cases filed by Noranda and 37 residential customers with the MoPSC in February 2014; the outcome of Ameren Illinois' natural gas rate case filed in 2013;appeal of the court appeals of Ameren Missouri's and Ameren Illinois'ICC's electric rate ordersorder issued in 2012; Ameren Missouri's FAC prudence review and the related request for an accounting authority order;December 2013; Ameren Illinois' request for rehearing of a July 2012 FERC order regarding the inclusion of acquisition premiums in Ameren Illinoisits transmission rates; and future regulatory, judicial, or legislative actions that seek to change regulatory recovery mechanisms;
the effect of Ameren Illinois participating in a performance-based formula ratemaking process under the IEIMA, including the direct relationship between Ameren Illinois' return on common equity and the 30-year United States Treasury bond yields, the related financial commitments required by the IEIMA, and the resulting uncertain impact on the financial condition, results of operations, and liquidity of Ameren Illinois;
Ameren's eventual exit from the Merchant Generation business could resulteffects of Ameren Illinois' expected participation, beginning in impairments2015, in the regulatory framework provided by the state of long-lived assets, disposal-related losses, contingencies, reductionIllinois' Natural Gas Consumer, Safety and Reliability Act, which allows for the use of existing deferred tax assets, or could have other adverse impacts on the financial condition, resultsa rider to recover costs of operations and liquidity of Ameren;certain natural gas infrastructure investments made between rate cases;
the effects of, or changes to, the Illinois power procurement process;
the effects of increased competition in the future due to,
among other things, deregulation of certain aspects of our business at either the state or federal levels and the implementation of deregulation;
changes in laws and other governmental actions, including monetary, fiscal, and tax policies;
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 Ameren Missouri and Marketing Company;
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;
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;
increasing capital expenditure and operating expense requirements and our ability to timely recover these costs;
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 theour ability to recover the costs for such commodities;
the effectiveness of our risk management strategies and the use of financial and derivative instruments;
the level and volatility of future prices for power in the Midwest, which may have a significant effect on the financial condition of Ameren's Merchant Generation segment;
the development of a multiyear capacity market within MISO and the outcomes of MISO's inaugural annual capacity
auction in 2013;
business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products;
disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that may make the Ameren Companies' access to necessary capital, including short-term credit and liquidity, impossible, more difficult, or more costly;
our assessment of our liquidity, including liquidity concerns for Ameren's Merchant Generation business, and specifically for Genco, which has limited access to third-party financing sources;liquidity;
the impact of the adoption of new accounting guidance and the application of appropriate technical accounting rules and guidance;
actions of credit rating agencies and the effects of such actions;
the impact of weather conditions and other natural phenomena on us and our customers, including the impacts of droughts, which may cause lower river levels and could limit our energy centers' ability to generate power;customers;
the impact of system outages;
generation, transmission, and distribution asset construction, installation, performance, and cost recovery;
the effects of our increasing investment in electric transmission projects and uncertainty as to whether we will achieve our expected returns in a timely fashion, if at all;
the extent to which Ameren Missouri prevails in its claims
against insurers in connection with its Taum Sauk pumped-storage hydroelectric energy center incident;
the extent to which Ameren Missouri is permitted by its regulators to recover in rates the investments it made in connection with additional nuclear generation at its Callaway energy center;
operation of Ameren Missouri's Callaway energy center, including planned and unplanned outages, and decommissioning costs;
the effects of strategic initiatives, including mergers, acquisitions and divestitures, and any related tax implications;
the impact of current environmental regulations on utilities and power generating companies and new, more stringent or changing requirements, including those related to greenhouse gases, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of our energy centers, increase our costs, result in an impairment of our assets, result in sales of our assets, reduce our customers' demand for electricity or natural gas, or otherwise have a negative financial effect;
the impact of complying with renewable energy portfolio requirements in Missouri;
labor disputes, workforce reductions, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets;
the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit agreements, and financial instruments;
the cost and availability of transmission capacity for the energy generated by Ameren's and Ameren Missouri's energy centers or required to satisfy energy sales made by Ameren or Ameren Missouri;
the inability of Dynegy and IPH to satisfy their indemnity and other obligations to Ameren in connection with the divestiture of New AER to IPH;
legal and administrative proceedings; and
acts of sabotage, war, terrorism, cybersecuritycyber attacks 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.
PART I
GENERAL
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 Ameren Missouri and CIPSCO Inc. Ameren acquired CILCORP in 2003
and IP in 2004. Ameren’s primary assets are its equity interests in its subsidiaries, including Ameren Missouri and Ameren Illinois and AER.Illinois. 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. In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end
Below is a summary description of Ameren Missouri and Ameren Illinois and AER.Illinois. A more detailed description can be found in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.
Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.
Ameren Illinois operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business and is developing the Illinois Rivers project. The Illinois Rivers project is a MISO-approved project to build a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri at an estimated cost of $1.1 billion.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. On December 2, 2013, Ameren completed the divestiture of New AER to IPH. On January 31, 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for additional information.
As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the gas-fired energy centers qualified for discontinued operations presentation beginning March 14, 2013. In addition, as of December 2, 2013, Ameren abandoned the Meredosia and Hutsonville energy centers upon the completion of the divestiture of New AER to IPH. Ameren is prohibited from operating these energy centers through December 31, 2020, as a provision of the Illinois Pollution Control Board's November 2013 order granting IPH a variance of the MPS. As a result, Ameren determined that the Meredosia and Hutsonville energy centers qualified for discontinued operations presentation as of December 2, 2013. The Meredosia and Hutsonville energy centers ceased operations at December 31, 2011, and therefore 2011 was the last year those energy centers had a material effect on Ameren's consolidated financial statements. As a result of these events, Ameren has segregated New AER’s and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers’ operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise stated, the following sections within Part I, Item 1, of this report exclude discontinued operations for all periods presented. See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for additional information regarding that presentation.
AER consists of non-rate-regulated operations, including Genco, AERG, Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.
The following table presents our total employees at December 31, 2012:2013 : |
| | |
Ameren(a)
| 9,097 |
|
| Ameren Missouri | 3,9973,932 |
|
| Ameren Illinois | 2,994 |
|
AER | 7133,133 |
|
| Ameren Services and Other | 1,3931,462 |
|
| Ameren | 8,527 |
|
| |
(a) | Total for Ameren includes Ameren registrant and nonregistrant subsidiaries. |
As of January 1, 2013,2014, the IBEW, the IUOE, the LIUNA, and the UA labor unions collectively represented about 57%56% of Ameren’s total employees. They represented 64% of the employees at Ameren Missouri and 63%61% at Ameren Illinois. The collective bargaining agreements have three-two- to five-yearsix-year terms, and expire between 20132015 and 2016. Several collective bargaining agreements between Ameren subsidiaries and the IBEW, IUOE, the LIUNA and the UA labor unions, covering approximately 2,900 employees expire during 2013.2017.
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.
BUSINESS SEGMENTS
Ameren has three reportingtwo reportable segments: Ameren Missouri and Ameren Illinois, and Merchant Generation.Illinois. See Note 1817 – Segment Information under Part II, Item 8, of this report for additional information on reporting segments.
RATES AND REGULATION
Rates
The rates that Ameren Missouri, and Ameren Illinois and ATXI 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 Ameren Missouri and Ameren Illinois 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, customer intervention, economic conditions, public policy, and social and political views. Decisions made by these governmental entities regarding rates are largely outside of Ameren Missouri’s and Ameren Illinois’our 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, Ameren Missouri and Ameren Illinois. Rate orders are also subject to appeal, which creates additional uncertainty as toThe extent of the rates Ameren Missouriregulatory lag varies for each of Ameren's electric and Ameren Illinois are ultimately allowed to charge for their services.natural gas jurisdictions, with our FERC-regulated electric jurisdictions experiencing the least amount of regulatory lag. The effecteffects of regulatory lag on Ameren Illinois’ electric distribution business isare mitigated to some extent through a variety of means including the use of the formula ratemaking regulatory framework established under the IEIMA. Beginning in 2013, regulatory lag on Ameren Illinois' and ATXI's electric transmission business will be mitigated to some extent through the use of the FERC revenue requirement reconciliation. To mitigate regulatory lag on Ameren Illinois' natural gas distribution business, recent rate requests have been filed with the ICC using a future test year.year, the implementation of trackers and riders, the deferral of depreciation for assets not yet included in rate base, and by regulatory frameworks that include annual revenue requirement reconciliations.
The ICC regulates rates and other matters for Ameren Illinois and the ICC regulates non-rate utility matters for ATXI. ATXI does not have retail distribution customers, and therefore the ICC does not have authority to regulate its rates. The MoPSC
regulates rates and other matters for Ameren Missouri. The FERC regulates Ameren Missouri, Ameren Illinois ATXI, Genco, EEI, and AERGATXI as to their ability to charge market-based rates for the wholesale sale and transmission of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.
About 53%The following table summarizes, by rate jurisdiction, the rate orders in effect for customer billings for each of Ameren’s electric and 15%Ameren's rate-regulated utilities as of itsJanuary 1, 2014.
|
| | | | | |
| | Regulator | Allowed Return on Equity | Percent of Common Equity | Rate Base (in billions) | Portion of Ameren's 2013 Operating Revenues(a) |
| Ameren Missouri | | | | | |
Electric service(b)(c) | MoPSC | 9.8% | 52.3% | $6.8 | 58% |
Natural gas delivery service(d) | MoPSC | (e) | 52.9% | $0.2 (e) | 3% |
| Ameren Illinois | | | | | |
Electric distribution delivery service(f) | ICC | 8.7% | 51.0% | $2.0 | 23% |
Natural gas delivery service(g) | ICC | 9.1% | 51.7% | $1.1 | 14% |
Electric transmission delivery service(h) | FERC | 12.38% | 55.2% | $0.7 | 2% |
| ATXI | | | | | |
Electric transmission delivery service(h) | FERC | 12.38% | 56.0% | $0.2 | (i) |
| |
| (a) | Includes pass-through costs recovered from customers, such as purchased power for electric distribution delivery service and gas purchased for resale for natural gas delivery service. |
| |
| (b) | Ameren Missouri electric generation, transmission, and delivery service rates are bundled together and charged to retail customers under a combined electric service rate. |
| |
| (c) | Based on MoPSC's December 2012 rate order, which became effective on January 2, 2013. |
| |
| (d) | Based on MoPSC's January 2011 rate order, which became effective on February 20, 2011. |
| |
| (e) | Ameren Missouri's last natural gas rate order did not specify the allowed return on equity or rate base. |
| |
| (f) | Based on the ICC's December 2013 rate order, which became effective on January 1, 2014. The December 2013 rate order was based on 2012 recoverable costs, expected net plant additions for 2013, and the monthly yields during 2012 of the 30-year United States treasury bonds plus 580 basis points. Ameren Illinois' 2014 electric distribution delivery service revenues will be based on its 2014 actual recoverable costs, rate base, and return on common equity, as calculated under the IEIMA's performance-based formula ratemaking framework. |
| |
| (g) | Based on the ICC's December 2013 rate order, which became effective on January 1, 2014. The rate order was based on a 2014 future test year. |
| |
| (h) | Transmission rates are updated and become effective each January using a company-specific, forward-looking rate formula framework, which is based on that year's forecasted information. |
Ameren Missouri
Electric
Ameren Missouri’s electric operating revenues wereare subject to regulation by the MoPSC in the year ended December 31, 2012. About 29% of Ameren’s electric and 85% of its natural gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2012. Wholesale revenues for Ameren Missouri, Ameren Illinois, Genco, Marketing Company and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.
Ameren Missouri
Electric
Almost 100% of Ameren Missouri’s electric operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2012.
MoPSC. In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenuesrates for electric service of $260 million, including $84 million related to an anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its July 2011 electric rate order. The annual increase
also included $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other non-fuel costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The revenue increase was based on a 9.8% return on equity, a capital structure composed of 52.3% common equity, and a rate base of $6.8 billion. The newThese rates became effective on January 2, 2013.
If certain criteria are met, Ameren Missouri’s electric rates may be adjusted without a traditional rate proceeding. The FAC permits Ameren Missouri to recover, through customer rates, 95% of prudently incurredchanges in net energy costs greater than or less than the amount set in base rates without a traditional rate proceeding, subject to prudence reviews. Net energy cost includes fuel, emission allowances, purchased power costs, certain fuel additives, transmission costs and revenues, and MISO costs and revenues, tonet of off-system sales revenues. Similarly, all of Ameren Missouri's MEEIA costs, including energy efficiency program costs, projected lost revenues, and potential incentive awards, are recovered through a rider that may be passed directlyadjusted without a traditional rate proceeding.
In addition to customers. The MoPSC's December 2012 electric rate order changed the FAC and the MEEIA recovery
mechanisms, Ameren Missouri employs other cost recovery mechanisms including a vegetation management and infrastructure inspection cost tracker, a pension and postretirement benefit cost tracker, an uncertain tax position tracker, a renewable energy standards cost tracker, solar rebate program tracker, and a storm cost tracker. Each of these trackers allows Ameren Missouri to include activated carbon, limestonerecord the difference between the level of incurred costs under GAAP and ureathe level of such costs along with transmission revenues, startingbuilt into rates as a regulatory asset or regulatory liability, which will be included in 2013.rates in a future rate order.
FERC regulates the rates charged and the terms and conditions for electric transmission services. Each RTO separately files a regional transmission tariff for approval by FERC. All transmission service within that RTOBecause Ameren Missouri is then subjected to that tariff. As a member of MISO, Ameren Missouri’sits transmission rate is calculated in accordance with the MISO OATT. The transmission rate is updated in June of each year; it is based on Ameren Missouri’s filings with FERC. This rate is not directly charged to Missouri retail customers, because in Missouri the MoPSC includes transmission-related costs and revenues in setting bundled retail rates. As discussed above, Ameren Missouri transmission revenues, as well as certain transmission costs paid to MISO for transmission services, are included in the FAC.
Natural Gas
All of Ameren Missouri’s natural gas operating revenues wereare subject to regulation by the MoPSC. The last natural gas delivery
service rate order was issued by the MoPSC in the year ended December 31, 2012. In January 2011, the MoPSC approved a stipulation and agreement that allowed Ameren Missouri to increase annual natural gas revenues by $9 million.2011.
If certain criteria are met, Ameren Missouri’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 customers. The ISRS also permits certain prudently incurred natural gas infrastructure replacement costs to be passed directly to customers.recovered from customers on a more timely basis between rate cases. The return on equity to be used by Ameren Missouri for purposes of the ISRS tariff filing is 10%. An ISRS tariff was approved and became effective in October 2013 for the recovery of eligible infrastructure system replacement investments made from January 2011 through May 2013, which resulted in a $1 million annual increase in rates.
For additional information on Missouri rate matters, including Ameren Missouri’s 2012 electric rate order and the related court appeals, 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
Electric
About 99% of Ameren Illinois’Illinois' electric operating revenues wereare subject to regulationeither ICC or FERC regulation. Ameren Illinois' electric distribution delivery service is regulated by the ICC, in the year ended December 31, 2012,while its electric transmission delivery service is regulated by FERC. In 2013, Ameren Illinois' electric distribution delivery service comprised 90% of its total electric operating revenues, with the remainder subjectof its electric operating revenues related to FERC regulation.electric transmission delivery service.
Under the Illinois Customer Choice Law,law, all electric customers in Illinois may choose their own electric energy provider. However, Ameren Illinois is required to serve as the provider of last resort (POLR) for electric customers within its territory who have not chosen an alternative retail electric supplier. Ameren Illinois’ obligation to provide POLR electric service varies by customer size. Ameren Illinois is not required to offer fixed-priced electric service to customers with electric demands of 400 kilowatts or greater, as the market for service to this group of customers has been declared competitive. Power and related procurement costs incurred by Ameren Illinois are passed directly to its customers through a cost recovery mechanism.
In 2012, Ameren Illinois elected to participateparticipates in the performance-based formula ratemaking process established pursuant to the IEIMA by filing initial performance-based formula rates with the ICC.IEIMA. The IEIMA was designed to provide for the recovery of actual costs of electric delivery service that are prudently incurred and to reflect the utility's actual regulated capital structure through the inclusion of a formula for calculating the return on equity component of the cost of capital. The return on equity component of the formula rate is equal to the average for the calendar year of the monthly yields of 30-year United States treasury bonds plus 590 basis points for 2012 and 580 basis points thereafter.points. Ameren Illinois' actual return on equity relating to electric delivery service will beis subject to a collar adjustment on earnings in excess of
50 basis points abovegreater than or belowless than its allowed return. The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year, including an allowed return on equity. This annual revenue reconciliation, along with the collar adjustment, if necessary, will be collected from or refunded to customers in a subsequent year.
Ameren Illinois is also subject to performance standards under the IEIMA. Failure to achieve the standards willwould result in a reduction in the company's allowed return on equity calculated under the formula. The performance standards include improvements in service reliability to reduce both the frequency and duration of outages, reduction in the number of estimated bills, reduction of consumption on inactive meters, and a reduction in uncollectible accounts expense. The IEIMA provides for return on equity penalties totaling up to 30 basis points in 2013 through 2015, 34 basis points in 2016 through 2018, and 38 basis points in 2019 through 2022 if the performance standards are not met. The formula ratemaking process is effective until the end of 2017, but could be extended by the Illinois General Assembly for an additional five years. The formula ratemaking
process would also terminate if the average residential rate increaseswere to increase by more than 2.5% annually from June 2011 through May 2014. The average residential rate includes generation service, which is outside of Ameren Illinois’ control, as Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. Ameren Illinois does not expect the annual increase in its average residential rate to exceed 2.5% through May 2014.
Between 2012 and 2021, Ameren Illinois is required, pursuant to the IEIMA, to invest $625 million in capital expendituresprojects incremental to Ameren Illinois' average electric delivery service capital expendituresprojects for calendar years 2008 through 2010 to modernize its distribution system. Through 2013, Ameren Illinois invested $61 million in IEIMA capital projects toward its $625 million requirement. Such investments are expected to encourage economic development and to create an estimated 450 additional jobs within Illinois. Ameren Illinois is subject to monetary penalties if 450 additional jobs are not created during the peak program year. Also,
Ameren Illinois is required to contribute $1 million annually for certain nonrecoverable customer assistance programs and $1 million annually to the Illinois Science and Energy Innovation Trust for as long as Ameren Illinois participates in the formula ratemaking process. Ameren Illinois also was required to make a one-time $7.5 million nonrecoverable donation to the Illinois Science and Energy Innovation Trust in 2012.
Ameren Illinois' initial filing under IEIMA was based on 2010 recoverable costs and expected net plant additions for 2011 and 2012. In September 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $779 million, which was a $55 million decrease from the electric delivery service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The rates became effective on October 19, 2012, and were effective through the end of 2012. In October 2012, Ameren Illinois filed an appeal of the ICC order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes that the ICC has incorrectly implemented the IEIMA by using an average rate base as opposed to a year-end rate base in setting rates, through its treatment of accumulated deferred income taxes, and through the method it used for calculating the equity portion of Ameren Illinois' capital structure and the method for calculating interest on the revenue requirement reconciliation and return on equity collar. The ICC's September 2012 order jeopardizes Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is reducing its IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to effectuate with the law. Although Ameren Illinois intends to meet its IEIMA capital spending requirements, it is proceeding on a slower investment schedule than previously contemplated.
In April 2012, Ameren Illinois submitted to the ICC an update filing under IEIMA based on 2011 recoverable costs and expected net plant additions for 2012. In December 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $764 million, which was a $15 million decrease in the revenue requirement allowed in the ICC
initial filing order. The rates became effective on January 1, 2013, and will be effective through the end of 2013. Ameren Illinois will submit to the ICC during the second quarter of 2013 an update filing based on 2012 recoverable costs and expected net plant additions for 2013, which will determine rates that are effective during 2014.
In December 2012, the ICC approved Ameren Illinois' advanced metering infrastructure deployment plan, which outlines how Ameren Illinois will comply with the IEIMA requirement to spend $360 million on smart grid assets over ten years on a cost-beneficial basis to its electric customers. The plan targets the second quarter of 2014 to begin installation of smart meters.
Also, Ameren Illinois has approval from the ICC to useemploys cost recovery mechanisms for power procurement, energy efficiency programs, certain environmental costs, and bad debt expense not recovered in base rates.
Ameren Illinois also has a tariff rider to recover the costs of certain asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At December 31, 2012, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates,claims.
Because Ameren Illinois will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP’s historical service territory. Similarly, the rider will permit recovery only from customers within IP’s historical service territory.
As a member of MISO, Ameren Illinois'its transmission rates arerate is calculated in accordance with the MISO OATT. Currently, the FERC-allowed return on common equity in the ratemaking formula for MISO transmission owners is 12.38%. Ameren Illinois has received FERC approval to use a company-specific, forward-looking rate formula templatesframework in setting its transmission rates. These forward-looking rates are updated ineach January each year based onwith forecasted information, with an annuala subsequent reconciliation during the year to adjust for the actual revenue requirement based on the costs incurred.and actual billed revenues, which will be used to
adjust billing rates in a subsequent year. In Illinois, the AMIL pricing zone rate is charged directly to wholesale customers and alternative retail electric suppliers, which serve unbundled retail load. For Ameren Illinois retail customers who have not chosen an alternative retail electric supplier, the AMIL transmission rate, as well asand other MISO-related costs are collected through a rider mechanism in Ameren Illinois' retail distribution tariffs.
Natural Gas
All of Ameren Illinois’ natural gas operating revenues wereare subject to regulation by the ICC in the year endedICC.
In December 31, 2012.
On January 25, 2013, Ameren Illinois filed a request with the ICC toissued a rate order that approved an increase its annualin revenues for natural gas delivery service by $50of $32 million. The requestrevenue increase was based on a 10.4%9.1% return
on equity, a capital structure composed of 51.8%51.7% common equity, and a rate base of $1.1 billion. In an attempt to reduce regulatory lag,The rate order was based on a 2014 future test year. The rate changes became effective January 1, 2014. Ameren Illinois is using a future test year, 2014,expects to file an appeal of the ICC's order to the Appellate Court in this proceeding. A decision by the ICC in this proceeding is required by December 2013. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect. March 2014.
If certain criteria are met, Ameren Illinois’ 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 customer.customers. Also, Ameren Illinois has approval from the ICC to useemploys cost recovery mechanisms for energy efficiency programs, certain environmental costs, and bad debt expense not recovered in base rates.
In July 2013, Illinois enacted the Natural Gas Consumer, Safety and Reliability Act, which encourages Illinois natural gas utilities to accelerate modernization of the state's natural gas infrastructure and provides additional ICC oversight of natural gas utility performance. The law allows natural gas utilities the option to file for, and requires the ICC to approve, a rate rider mechanism to recover costs of certain natural gas infrastructure investments made between rate cases. The law does not require a minimum level of investment. Ameren Illinois expects to begin including investments under this regulatory framework in 2015. Ameren Illinois' decision to accelerate modernization of its natural gas infrastructure under this regulatory framework is dependent upon multiple considerations, including the allowed return on equity under this regulatory framework compared with other Ameren and Ameren Illinois investment options.
ATXI
Similar to Ameren Illinois, ATXI is a member of MISO, and its transmission rate is calculated in accordance with the MISO OATT. Currently, the FERC-allowed return on common equity in the ratemaking formula for MISO transmission owners is 12.38%. ATXI has received FERC approval to use a company-specific, forward-looking rate formula framework in setting its transmission rates. These forward-looking rates are updated each January with forecasted information, with a subsequent reconciliation during the year to adjust for the actual revenue requirement and actual billed revenues, which will be used to adjust billing rates in a subsequent year. Additionally, FERC has approved transmission rate incentives relating to the three MISO-approved
multi-value projects discussed below, which allow construction work in progress to be included in rate base, thereby improving cash flows.
The three MISO-approved multi-value projects being developed by ATXI are the Illinois Rivers, Spoon River, and Mark Twain projects. The first project, Illinois Rivers, involves the construction of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. ATXI obtained a certificate of public convenience and necessity and project approval from the ICC for the entire Illinois Rivers project. A full range of construction activities for the Illinois Rivers project is scheduled in 2014. The first sections of the Illinois Rivers project are expected to be completed in 2016. The last section of this project is expected to be completed in 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects approved by MISO. These two projects are expected to be completed in 2018. The total investment in these three projects is expected to be more than $1.4 billion through 2019.
For additional information on Illinois rate matters, including the IEIMA and the Ameren Illinois' natural gas case filed in January 2013, 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 energy centers to have 5,522 megawatts of capacity available for the 2013 peak summer electrical demand. In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. As discussed below, Genco and AERG 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 to mitigate risks through a variety of 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 hedging transactions, including options and other derivatives. Marketing Company enters into long-term and short-term contracts. Marketing Company’s counterparties include cooperatives, municipalities, residential, commercial and industrial customers, power marketers, MISO, PJM and investor-owned utilities, including Ameren Illinois. Illinois law allows municipalities and counties to negotiate the purchase price of electricity on behalf of residential and small business utility customers. In 2012, Marketing Company began serving those Illinois municipalities electing to aggregate their residential and small commercial electric supply load, and which selected Marketing Company as their provider. For additional information on Marketing Company’s hedging activities, 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 under Part II, Item 8, of this report.
General Regulatory Matters
Ameren Missouri and Ameren Illinois Genco, AERG and Marketing Company must receive FERC approval to enter into various transactions, including to issuesuch as issuing short-term debt securities and to conductconducting certain acquisitions, mergers, and consolidations involving electric utility holding companies havingwith 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.
Ameren Missouri, Ameren Illinois Genco, AERG and ATXI are also subject to mandatory reliability standards, including cybersecurity standards adopted by FERC, to ensure the reliability of the bulk power electric system. These standards are developed and enforced by NERC pursuant to authority given to it by the FERC. If Ameren or its subsidiaries were found not to be in compliance with any of these mandatory reliability standards, they could incur substantial monetary penalties and other sanctions.
Under PUHCA 2005, FERC and any state public utility regulatory agenciesagency 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 the MoPSC and the ICC to request that FERC review cost allocations by Ameren Services to other Ameren companies.
Operation of Ameren Missouri’s Callaway energy center is
subject to regulation by the NRC. Its facility operating license expires on June 11,in October 2024. In December 2011, Ameren Missouri submitted a license extension application withto the NRC to extend the energy center's operating license to 2044. There is no date by which the NRC must act on this relicensing request. Ameren Missouri’s Osage hydroelectric energy center and Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center, 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 Ameren Missouri’s Osage hydroelectric energy center expires onin March 30, 2047. In June 2008, Ameren Missouri filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric energy center for another 40 years. The existing FERC license expired on June 30, 2010. OnIn July 2, 2010, Ameren Missouri received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. FERC is reviewing the relicensing application. A FERC order is expected in 2013 or 2014. Ameren Missouri cannot predict the ultimate outcome of the order. Ameren Missouri’s Keokuk energy center 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, Note 10 -– Callaway Energy Center, 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 Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center.report.
Environmental Matters
Certain of our operations are subject to federal, state, and local environmental statutes orand regulations relating to the safety and health of personnel, the public, and the environment. These environmental statutes and regulations include requirements forrelating to identification, generation, storage, handling, transportation, disposal, recordkeeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials; safety and health standards; and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants the protection of natural and cultural resources, 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 or we could be ordered by the courts to pay private parties. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.regulations that currently apply to our operations.
In addition to existing laws and regulations, including the Illinois MPS that applies to AER's energy centers in Illinois, theThe EPA is developing environmental regulations that will have a significant impact on the electric utility industry. TheseOver time, compliance with these regulations could be particularly burdensomecostly for certain companies, including Ameren Ameren Missouri, Genco, and AERG, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions;CO2 emissions from new energy centers; revised national ambient air quality standards for ozone, fine particulates, SO2, and NO2x emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions, and fine particulate matter emissions from energy centers; a regulation that governs governing
management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new effluent standards applicable to waste water discharges from energy centers and new regulations under the Clean Water Act that could require significant capital expenditures, such as for newmodifications to water intake structures or new cooling towers at our energy centers. The EPA has proposedis expected to propose CO2 limitsstandards for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing fossil fuel-fired electric generation units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012.uncertain. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/orand increased operating costs over the next five to ten years for Ameren and Ameren Missouri and AER.Missouri. Compliance
with these environmental laws and regulations could be prohibitively expensive. If they are, these regulationsexpensive or could require us to closeresult in the closure or to significantly alteralteration of the operation of some of our energy centers, which could have an adverse effect on our resultscenters. Ameren and Ameren Missouri would expect these costs to be recoverable through rates, but the nature and timing of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.
The decision to make pollution control equipment investments at our Merchant Generation business depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in that year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices,costs, as well as the impact from the stay of the CSAPR. As aapplicable regulatory framework, could result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center.regulatory lag.
For additional discussion of environmental matters, including NOx, SO2, and mercury emission reduction requirements, remediation efforts, and a discussion of the EPA’s allegations of violations of the Clean Air Act and Missouri law in connection with projects at Ameren Missouri's Rush Island energy center, and the EPA's Notice of Violation of permitting requirements at Genco's Newton energy center, 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 OF ELECTRIC POWER
Ameren owns an integrated transmission system that comprises the transmission assets of Ameren Missouri, Ameren Illinois and ATXI. Ameren also operates two balancing authority areas, AMMO (which includes Ameren Missouri)Missouri's customers), and AMIL (which includes Ameren Illinois, ATXI, AERG, and Genco excluding EEI and Genco’s Elgin CT energy center)Illinois' customers). During 2012,2013, the peak demand was 8,8688,146 megawatts in AMMO and 9,7208,899 megawatts in AMIL. The Ameren transmission system directly connects with 15 other balancing authority areas for the exchange of electric energy.
Ameren Missouri, Ameren Illinois and ATXI are transmission-owning members of MISO. Transmission service on the Ameren transmission system 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 the transmission systems of MISO, the Tennessee Valley Authority, and Louisville Gas and Electric Company. EEI’s energy centers are dispatched separately from those of Ameren Missouri, Genco and AERG. Ameren Missouri is authorized by the MoPSC to participate in MISO, subject to certain conditions, through May 2016.
In May 2011 FERC approved transmission rate incentives for2016, including the Illinois Rivers project, whichcondition that Ameren Missouri later file a study with the MoPSC that evaluates the costs and benefits of Ameren Missouri's continued participation in MISO, as it has periodically done since its MISO participation began in 2003. The next study is being developed by ATXI. In December 2011, MISO approved the Illinois Rivers project as well as the Spoon River and Mark Twain projects. The total investment in these three MISO-approved projects is expectedrequired to be more than $1.3 billion from 2013 to 2019. These projects are located primarilyfiled with the MoPSC in Illinois and Missouri.
In February 2012, FERC approved ATXI's request for a forward-looking rate calculation with an annual reconciliation adjustment, as well as ATXI's request for implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project. In November 2012, FERC approved transmission rate incentives for the Spoon River project and the Mark Twain project. FERC also approved a forward-looking rate calculation with an annual reconciliation adjustment for Ameren Illinois' electric transmission business.2015.
The Ameren Companies and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in 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 NERC and its regional entities, such as SERC, which are all enforced by FERC. The Ameren Companies must comply with these standards, which are in place 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
Ameren Missouri’s electric supply is obtained primarily from its own generation. Factors that could cause Ameren Missouri to purchase power include, among other things, absence of sufficient owned generation, energy center outages, the fulfillment of renewable energy portfolio 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.
Ameren Missouri continues to evaluate its longer-term needs for new baseload, including nuclear and peaking electric generation capacity. The MoPSC's December 2012 electric rate order approvedSee Energy Efficiency in this section for information on Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs and associated cost recovery mechanisms and incentive awards. The order allows for Ameren Missouri to collect its program costs and 90% of its projected lost revenue from customers over the same three-year period starting on January 2, 2013. The remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings.mechanisms. The potential need for new generating plantenergy center construction is dependent on several key factors, including:including continuation of energy efficiency programs beyond 2015, load growth, customer participation in energy efficiency programs, and the potential for more stringent environmental regulation of coal-
firedcoal-fired energy centers, which could lead to the retirement of current baseload assets.assets or alterations in the manner in which those assets operate. Because of the significant time required to plan, acquire permits for, and build a baseload power plant,energy center, Ameren Missouri continues to study future plant alternatives and is taking steps to preserve options to meet future demand. These steps include evaluating the potential for further energy efficiency programs in the long term,and evaluating potential sites for natural gas-fired generation. Ameren Missouri
is also exploring options to expand renewable generation and pursuing DOE funds through a partnership with Westinghouse for development of small modular reactor technology for nuclear power.further diversify its generation portfolio. Ameren Missouri's next Integrated Resource Plan filing with the MoPSC is due in October 1, 2014.
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
Any electric supply purchased by Ameren Illinois for its retail customers comes either through an annual procurement process conducted by the IPA or through markets operated by MISO. The power and related procurement costs incurred by Ameren Illinois are passed directly to its customers through a cost recovery mechanism.
The IPA administers aan RFP process that procures Ameren Illinois’ expected supply obligation. Since the RFP process began in 2009, the ICC has approved the outcomes of multiple electric power procurement RFPs for energy, capacity, and renewable energy credits covering different time periods.
A portion of the electric power supply required for Ameren Illinois to satisfy its distribution customers’ requirements is
purchased in the RFP process administered by the IPA from Marketing Company, on behalf of Genco and AERG, and from Ameren Missouri.
Under Illinois law, transmission and distribution service rates are regulated, while electric customers are allowed to purchase generationpower from an alternative retail electric supplier. At December 31, 2012,2013, approximately 396,000768,000 retail customers representing approximately 61%72% of Ameren Illinois' annual retail kilowatthour sales had elected to purchase their electricity from an alternative retail electric supplier.suppliers. Customers who receive electricity from an alternative retail electric suppliersuppliers continue to pay a delivery charge to Ameren Illinois for the distribution services they receive from Ameren Illinois.
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 of the capacity and energy available from Genco’s and AERG’s energy centers. 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 May 31, 2016. All of Genco’s, AERG’s and EEI’s energy centers compete for the sale of energy and capacity in the competitive energy markets through Marketing Company.
POWER GENERATION
The following table presents the source of electric generation, excluding purchased power, for the years ended December 31, 2013, 2012, 2011 and 2010:2011: | | | | Coal | | Nuclear | | Natural Gas | | Renewables(a) | | Oil | Coal | | Nuclear | | Natural Gas | | Renewables(a) | | Oil |
Ameren:(b) | | | | | | | | | | |
| Ameren and Ameren Missouri: | | | | | | | |
| 2013 | | 77 | % | | 19 | % | | (b) | | 3 | % | | (b) |
| 2012 | 81 | % | | 15 | % | | 3 | % | | 1 | % | | (c) |
| 73 |
| | 24 |
| | 1 | | 2 |
| | (b) |
| 2011 | 85 |
| | 12 |
| | 1 |
| | 2 |
| | (c) |
| 77 |
| | 19 |
| | 1 | | 3 |
| | (b) |
| 2010 | 85 |
| | 12 |
| | 1 |
| | 2 |
| | (c) |
| |
| Ameren Missouri: | | | | | | | | | | |
| 2012 | 73 | % | | 24 | % | | 1 | % | | 2 | % | | (c) |
| |
| 2011 | 77 |
| | 19 |
| | 1 |
| | 3 |
| | (c) |
| |
| 2010 | 77 |
| | 19 |
| | 1 |
| | 3 |
| | — |
| |
| Merchant Generation: | | | | | | | | | | |
| 2012 | 94 | % | | — |
| | 6 | % | | — |
| | — |
| |
| 2011 | 98 |
| | — |
| | 2 |
| | — |
| | (c) |
| |
| 2010 | 98 |
| | — |
| | 2 |
| | — |
| | (c) |
| |
| |
| (a) | Renewable power generation includes production from Ameren Missouri's hydroelectric, pumped-storage, and methane gas energy centers, but excludes purchased renewable energy credits. |
| |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
(c) | Less than 1% of total fuel supply. |
The following table presents the cost of fuels for electric generation for the years ended December 31, 2013, 2012, 2011, and 2010:2011:
| | Cost of Fuels (Dollars per Mmbtu) | 2012 | | 2011 | | 2010 | |
| Ameren: | | | | | | |
Cost of Fuels (dollars per mmbtu) | | 2013 | | 2012 | | 2011 |
| Ameren and Ameren Missouri: | | | | | | |
Coal(a) | $ | 2.081 |
| | $ | 1.931 |
| | $ | 1.848 |
| $ | 2.050 |
| | $ | 1.925 |
| | $ | 1.733 |
|
| Nuclear | 0.964 |
| | 0.750 |
| | 0.701 |
| 0.942 |
| | 0.964 |
| | 0.750 |
|
Natural gas(b) | 3.772 |
| | 6.097 |
| | 6.539 |
| 7.907 |
| | 4.517 |
| | 5.873 |
|
Weighted average – all fuels(c) | $ | 1.975 |
| | $ | 1.873 |
| | $ | 1.803 |
| $ | 1.874 |
| | $ | 1.743 |
| | $ | 1.610 |
|
| Ameren Missouri: | | | | | | |
Coal(a) | $ | 1.925 |
| | $ | 1.733 |
| | $ | 1.675 |
| |
| Nuclear | 0.964 |
| | 0.750 |
| | 0.701 |
| |
Natural gas(b) | 4.517 |
| | 5.873 |
| | 6.199 |
| |
Weighted average – all fuels(c) | $ | 1.743 |
| | $ | 1.610 |
| | $ | 1.563 |
| |
| Merchant Generation: | | | | | | |
Coal(a) | $ | 2.282 |
| | $ | 2.184 |
| | $ | 2.063 |
| |
Natural gas(b) | 3.392 |
| | 6.374 |
| | 6.972 |
| |
Weighted average – all fuels(c) | $ | 2.359 |
| | $ | 2.292 |
| | $ | 2.169 |
| |
| |
| (a) | The fuel cost for coal representsRepresents the cost of coal and the costs for transportation, which include hedges for railroad diesel fuel additives, and the cost of emission allowances.surcharges. |
| |
| (b) | The fuel cost for natural gas representsRepresents the cost of natural gas and firm and variable costs for transportation, storage, balancing, and fuel losses for delivery to the plant.energy center. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost for the energy centers. |
| |
| (c) | Represents all costs for fuels used in our energy centers, to the extent applicable, including coal, nuclear, natural gas, methane gas, oil, propane, tire chips, paint products, and handling. Oil,Methane gas, oil, propane, tire chips, and paint products are not individually listed in this table because their use is minimal. |
Coal
Ameren Missouri and the Merchant Generation business havehas agreements in place to purchase a portion of the coal they needit needs and to transport it to energy centers through 2019. Ameren Missouri and Merchant Generation expectexpects to enter into additional contracts to purchase coal from time to time. Coal supply agreements for Ameren Missouri have terms of up to six years, and expire between 2014 and 2017. Ameren Missouri has an ongoing need for coal to serve its native load customers, so it pursues a price hedgingprice-hedging strategy consistent with this requirement. Merchant Generation's forward coal requirements and coal supply agreements are dependent on the volume of power sales contracted. Merchant Generation strives to achieve increased margin certainty by aligning its fuel purchases with its power sales. Ameren Missouri burned 3419 million tons (Ameren Missouri – 19 million, Merchant Generation – 15 million) of coal in 2012.2013. See Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about coal supply contracts.
About 97%98% of Ameren’sAmeren Missouri’s coal (Ameren Missouri – 97%, Merchant Generation – 97%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. Ameren Missouri and Merchant Generation have a goal to maintain coal inventory consistent with their risk management policies. Inventory may be adjusted because of changes in burngeneration levels or uncertainties of supply due to 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, 2012,2013, coal inventories for Ameren Missouri were about 20% below targeted levels due to flooding and for Merchant Generation were at or above targeted levels.weather-related delivery delays. Disruptions in coal deliveries could cause Ameren Missouri and Merchant Generation 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
The steps in the process to provide nuclear fuel generally involve 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. Ameren Missouri has entered into uranium, uranium conversion, uranium enrichment, and fabrication contracts to procure the fuel supply for its Callaway nuclear energy center.
Fuel assemblies for the 2013 spring2014 fall refueling at Ameren Missouri's Callaway energy center were manufacturedare scheduled for manufacture and were delivereddelivery to the energy center in January 2013.during the period May to July 2014. Ameren Missouri also has agreements or inventories to
price-hedge approximately 99%100%, 52%71%, and 46%60% of Callaway's 2014, 2016 and 2017 refueling requirements, respectively. Ameren Missouri has uranium (concentrate and hexafluoride) inventories and supply contracts sufficient to meet all of its uranium and conversion requirements through at least through 2017.2018. Ameren Missouri has enriched uranium inventories and enrichment supply contracts sufficient to satisfy enrichment requirements through at least 2017.2018. Fuel fabrication services are under contract through 2014. Ameren Missouri expects to enter into additional contracts to purchase nuclear fuel. As a member of Fuelco, Ameren Missouri can join with other member companies to increase its purchasing power, enhance diversification, and pursue opportunities for volume discounts. The Callaway energy center normally requires refueling at 18-month intervals. The last refueling was completed in November 2011.May 2013. There is no refueling scheduled for 2015 and 2018. 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 for Generation
To maintain deliveries to natural gas-fired energy centers throughout the year, especially during the summer peak demand, Ameren’sAmeren Missouri’s portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines. Ameren Missouri and Merchant Generation primarily useuses 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 energy centers. 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.
Ameren Missouri’s and Merchant Generation's natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to theirits energy centers. This is accomplished by optimizing transportation and storage options and minimizing cost and price risk through various supply and price-hedging agreements that allow access to multiple gas pools, supply basins, and storage services. As of December 31, 20122013, Ameren Missouri had price-hedged about 34% and Merchant Generation had price hedged 5927% of its expected natural gas supply requirements for generation in 2013.2014.
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 suppliessupplied to its eligible retail customers as of June 1, 2008, with that percentage increasing to 10% by June 1, 2015, and to 25% by June 1, 2025. In 2012,For the 2013 plan year, Ameren Illinois procured approximatelymet its requirement that 8% of its total electricity for eligible retail customers be procured from renewable energy resources. Current forecasts indicate that Ameren Illinois has procuredcommitted to procure sufficient renewable energy credits under the IPA-administered procurement process to meet the renewable energy portfolio requirement through at least May 2017.2018. In December 2010, Ameren Illinois entered into 20-year agreements with renewable energy suppliers and commencedsuppliers. It began receiving renewable energy credits under these agreements in June 2012. Approximately 54%63% of the 20132014 plan year renewable energy requirement willis expected to be met through these agreements. The remaining requirement will be met through IPA procurements, which resulted in contracts that were executed in February 2012 with a term of June 2013 through December 2017.
In Missouri, utilities are required to purchase or generate from renewable energy sources electricity equaling at least 2% of native load sales, with that percentage increasing to at least 15% by 2021, subject to a 1% annual limit on customer rate impacts. At least 2% of each renewable energy portfolio requirement must be derived from solar energy. Ameren Missouri expects to satisfy the nonsolar requirement through 20172018 with its existing renewable generation, including the Maryland Heights energy center, along with a 15-year 102-megawatt power purchase agreement with a wind farm operator in Iowa that became
effective in 2009. The Maryland Heights energy center generates electricity by burning methane gas collected from a landfill. Currently, Ameren Missouri expects to meetis meeting the solar energy requirement through the purchase of solar-generated renewable energy credits and generation from solar panels installed on Ameren's general office building. However,St. Louis headquarters. In January 2014, Ameren Missouri announced its plans to build a solar energy center which will generate 5 megawatts of solar power. Construction is studying other options for compliance.expected to begin in the spring of 2014, and delivery of power to customers is expected by the end of 2014. In 2012,2013, Ameren Missouri purchased or generated approximately 3%about 5% of its native load sales from renewable energy resources.resources, meeting its requirements.
In 2012,Under the same Missouri statute requiring utilities to purchase or generate energy from renewable sources, Ameren Missouri began generating power at its Maryland Heights energy center. This energy center, located atis required to have a landfill in Maryland Heights, Missouri, hasrebate program to provide an incentive for customers to install solar generation on their premises. In accordance with the capability to generate up to approximately 15 megawatts of electricity by burning methane gas collected from the landfill.statute and a 2013 MoPSC order, Ameren Missouri signedis required to provide $92 million of solar rebates by 2020. Also included in its 2013 order, the MoPSC authorized Ameren Missouri to employ a 20-year supply agreementtracker allowing Ameren Missouri to record its costs incurred under its solar rebate program as a regulatory asset. Ameren Missouri will recover the costs of these rebates, and the carrying cost of the regulatory
asset, which is estimated to be $9 million, over a three-year period beginning with the landfill owner to purchase methane gas.effective date of its next electric rate case.
Energy Efficiency
Ameren’s rate-regulated utilities have implemented energy efficiency programs to educate and help their customers become more efficient users of energy. The MEEIA established a regulatory framework that, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. The law requires the MoPSC to ensure that a utility’s financial incentives are aligned to help customers use energy more efficiently, to provide timely cost recovery, and to provide earnings opportunities associated with cost-effective energy efficiency programs. Missouri does not have a law mandating energy efficiency standards.
The MoPSC's December 2012 electric rate order approved Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs, and associated cost recovery mechanisms and incentive awards. Beginning inIn 2013, Ameren Missouri will invest approximately $147invested $35 million over the next three years for energy efficiency programs. The orderAmeren Missouri expects to invest $48 million in 2014 and $64 million in 2015 for these programs. A MEEIA rider allows for Ameren Missouri to collect itsfrom or refund to customers through 2015 any annual difference in the actual amounts incurred and the projected amounts collected from customers for the MEEIA program costs and 90% of its projected lost revenue from customers over the same three years starting on January 2, 2013. The remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings.revenues.
Additionally, the orderMEEIA provides for an incentive award that would allow Ameren Missouri to earn additional revenues based on achievement ofby achieving certain energy efficiency goals, including approximately $19 million if 100% of its energy efficiency goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri's energy savings exceed those goals. Ameren Missouri must achieve at least 70% of its energy efficiency goals before it earns any incentive award. The recovery of the incentive award from customers, if the energy efficiency goals are achieved, would begin afteris expected in 2017 through the three-year energy efficiency plan is complete and upon the effective date of an electric service rate order or possibly with the future adoption of a rider mechanism.above-mentioned rider. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
Illinois has enacted a law requiring Ameren Illinois to offer energy efficiency programs. The law also allows recovery mechanisms of the programs’ costs. The ICC has issued orders
approving Ameren Illinois’ electric and natural gas energy efficiency plans as well as cost recovery mechanisms by which program costs can be recovered from customers. In addition, over a ten-year period,between 2012 and 2021, Ameren Illinois willis required, pursuant to the IEIMA, to invest an estimated $625 million in capital projects incremental to upgrade andAmeren Illinois' average electric delivery service capital projects for calendar years 2008 through 2010 to modernize its transmission and distribution infrastructure in accordance with the IEIMA.system. As part of these upgrades, Ameren Illinois expects to invest $360 million to installfor smart grid infrastructure, including smart meters, which could enableenables customers to improve efficiency. Ameren Illinois will begin the installation of smart meters during 2014.
NATURAL GAS SUPPLY FOR DISTRIBUTION
Ameren Missouri and Ameren Illinois are responsible for the purchase and delivery of natural gas to their utility customers. Ameren Missouri and Ameren Illinois each develop and manage a portfolio of natural 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 natural gas deliveries to customers throughout the year and especially during peak demand periods. Ameren Missouri and Ameren Illinois primarily use Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, Mississippi River Transmission Corporation, Northern Border Pipeline Company, and Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to transactions requiring physical delivery, 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. Natural gas purchase costs are passed on to customers of Ameren Missouri and Ameren Illinois under PGA clauses, subject to prudency reviews by the MoPSC and the ICC. As of December 31, 20122013, Ameren Missouri had price-hedged 8984%, and Ameren Illinois had price-hedged 81%77%, of its expected 2014 natural gas supply requirements for distribution in 2013.requirements.
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 Energy Center, Note 14 – Related Party Transactions, and Note 15 – Commitments and Contingencies under Part II, Item 8 of this report.
INDUSTRY ISSUES
We are facing issues common to the electric and natural gas utility industry and the merchant electric generation industry. These issues include:
continually developing and complex environmental laws, regulations and issues, including air and water quality standards, mercury emissions standards, and likely greenhouse gas limitations and CCR management requirements;
political and regulatory resistance to higher rates;
the potential for changes in laws, regulations, and policies at the state and federal level;
access to, and uncertainty in, the capital and credit markets;
cybersecurity risk, including loss of operational control of energy centers and electric and natural gas transmission and distribution systems and/or loss of data, such as utility customer data, account information, and compliance with related industry regulations;intellectual property through insider or outsider actions;
the potential for more intense competition in generation, supply and distribution, including new technologies;
pressure on customer growth and usage in light of current economic conditions and energy efficiency initiatives;
the potential for reregulation in some states, which could cause electric distribution companies to build or acquire energy centers and to purchase less power from electric generation companies such as Genco and AERG;
changes in the structure of the industry as a result of changes in federal and state laws, including the formation and growth of independent transmission entities;
increases, decreases, and volatility in power prices duepressure to reduce the balance of supply and demand and marginal fuel costs;
weakened financial strength of merchant generators, especially those with coal-fired energy centers, including their ability to generate positive cash flows in competitive markets as they seek to comply with environmental regulations;allowed return on common equity on FERC-regulated electric transmission assets;
the availability of fuel and increases or decreases in fuel prices;
the availability of qualified labor and material, and rising costs;
regulatory lag;
the influence of macroeconomic factors, such as yields on United States treasury securities, on allowed rates of return on equity provided by regulators;
decreased or negative free cash flows due to rising infrastructure investments and regulatory frameworks;
public concern about the siting of new facilities;
continually developing and complex environmental laws, regulations and requirements, including air and water quality standards, mercury emissions standards, and likely greenhouse gas limitations and CCR management requirements;
public concerns about the potential impacts to the environment from the combustion of fossil fuels;
aging infrastructure and the need to construct new power generation, transmission and distribution facilities, which have long time frames tofor completion, while at the same time, having little long-term visibility on power and commodity prices;prices and regulatory requirements;
legislation or proposals for programs to encourage or mandate energy efficiency and renewable sources of power;power, such as solar, and the macroeconomic debate of who should pay for those programs;
public concerns about nuclear generation and decommissioning and the disposal of nuclear waste; and
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 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.
OPERATING STATISTICS
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, | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Electric Sales – kilowatthours (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | 13,385 |
| | 13,867 |
| | 14,640 |
| 13,562 |
| | 13,385 |
| | 13,867 |
|
| Commercial | 14,575 |
| | 14,743 |
| | 15,002 |
| 14,634 |
| | 14,575 |
| | 14,743 |
|
| Industrial | 8,660 |
| | 8,691 |
| | 8,656 |
| 8,709 |
| | 8,660 |
| | 8,691 |
|
| Other | 126 |
| | 127 |
| | 129 |
| 125 |
| | 126 |
| | 127 |
|
| Native load subtotal | 36,746 |
| | 37,428 |
| | 38,427 |
| 37,030 |
| | 36,746 |
| | 37,428 |
|
| Off-system and wholesale | 7,293 |
| | 10,715 |
| | 9,796 |
| 6,128 |
| | 7,293 |
| | 10,715 |
|
| Subtotal | 44,039 |
| | 48,143 |
| | 48,223 |
| 43,158 |
| | 44,039 |
| | 48,143 |
|
| Ameren Illinois: | | | | | | | | | | |
| Residential | | | | | | | | | | |
| Power supply and delivery service | 9,507 |
| | 11,771 |
| | 12,340 |
| 5,474 |
| | 9,507 |
| | 11,771 |
|
| Delivery service only | 2,103 |
| | 77 |
| | 1 |
| 6,310 |
| | 2,103 |
| | 77 |
|
| Commercial | | | | | | | | | | |
| Power supply and delivery service | 2,985 |
| | 3,662 |
| | 4,419 |
| 2,606 |
| | 2,985 |
| | 3,662 |
|
| Delivery service only | 9,175 |
| | 8,561 |
| | 8,051 |
| 9,541 |
| | 9,175 |
| | 8,561 |
|
| Industrial | | | | | | | | | | |
| Power supply and delivery service | 1,595 |
| | 1,502 |
| | 1,389 |
| 1,667 |
| | 1,595 |
| | 1,502 |
|
| Delivery service only | 11,753 |
| | 11,360 |
| | 11,147 |
| 10,861 |
| | 11,753 |
| | 11,360 |
|
| Other | 523 |
| | 529 |
| | 545 |
| 522 |
| | 523 |
| | 529 |
|
| Native load subtotal | 37,641 |
| | 37,462 |
| | 37,892 |
| 36,981 |
| | 37,641 |
| | 37,462 |
|
| Merchant Generation: | | | | | | |
| Nonaffiliate energy sales | 25,552 |
| | 31,148 |
| | 30,788 |
| |
| Affiliate native energy sales | 1,679 |
| | 1,004 |
| | 949 |
| |
| Subtotal | 27,231 |
| | 32,152 |
| | 31,737 |
| |
| Eliminate affiliate sales | (1,679 | ) | | (1,004 | ) | | (949 | ) | (82 | ) | | — |
| | (17 | ) |
| Eliminate Ameren Illinois/Merchant Generation common customers | (7,261 | ) | | (5,454 | ) | | (5,016 | ) | |
| Ameren total | 99,971 |
| | 111,299 |
| | 111,887 |
| 80,057 |
| | 81,680 |
| | 85,588 |
|
| Electric Operating Revenues (in millions): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | $ | 1,297 |
| | $ | 1,272 |
| | $ | 1,193 |
| $ | 1,428 |
| | $ | 1,297 |
| | $ | 1,272 |
|
| Commercial | 1,088 |
| | 1,084 |
| | 1,004 |
| 1,216 |
| | 1,088 |
| | 1,084 |
|
| Industrial | 435 |
| | 438 |
| | 399 |
| 491 |
| | 435 |
| | 438 |
|
| Other | 104 |
| | 76 |
| | 91 |
| 61 |
| | 104 |
| | 76 |
|
| Native load subtotal | $ | 2,924 |
| | $ | 2,870 |
| | $ | 2,687 |
| $ | 3,196 |
| | $ | 2,924 |
| | $ | 2,870 |
|
| Off-system and wholesale | 208 |
| | 352 |
| | 343 |
| 183 |
| | 208 |
| | 352 |
|
| Subtotal | $ | 3,132 |
| | $ | 3,222 |
| | $ | 3,030 |
| $ | 3,379 |
| | $ | 3,132 |
| | $ | 3,222 |
|
| Ameren Illinois: | | | | | | | | | | |
| Residential | | | | | | | | | | |
| Power supply and delivery service | $ | 961 |
| | $ | 1,194 |
| | $ | 1,270 |
| $ | 501 |
| | $ | 961 |
| | $ | 1,194 |
|
| Delivery service only | 90 |
| | 3 |
| | — |
| 282 |
| | 90 |
| | 3 |
|
| Commercial | | | | | | | | | | |
| Power supply and delivery service | 254 |
| | 350 |
| | 425 |
| 215 |
| | 254 |
| | 350 |
|
| Delivery service only | 177 |
| | 157 |
| | 143 |
| 184 |
| | 177 |
| | 157 |
|
| Industrial | | | | | | | | | | |
| Power supply and delivery service | 57 |
| | 65 |
| | 66 |
| 70 |
| | 57 |
| | 65 |
|
| Delivery service only | 46 |
| | 43 |
| | 38 |
| 44 |
| | 46 |
| | 43 |
|
| Other | 154 |
| | 128 |
| | 119 |
| 165 |
| | 154 |
| | 128 |
|
| Native load subtotal | $ | 1,739 |
| | $ | 1,940 |
| | $ | 2,061 |
| $ | 1,461 |
| | $ | 1,739 |
| | $ | 1,940 |
|
| Merchant Generation: | | | | | | |
| Nonaffiliate energy sales | $ | 1,047 |
| | $ | 1,382 |
| | $ | 1,442 |
| |
| Affiliate native energy sales | 311 |
| | 232 |
| | 231 |
| |
| Other | 15 |
| | 12 |
| | 20 |
| |
| Subtotal | $ | 1,373 |
| | $ | 1,626 |
| | $ | 1,693 |
| |
| Eliminate affiliate revenues | (340 | ) | | (258 | ) | | (263 | ) | |
| Eliminate affiliate revenues and other | | (8 | ) | | (14 | ) | | (15 | ) |
| Ameren total | $ | 5,904 |
| | $ | 6,530 |
| | $ | 6,521 |
| $ | 4,832 |
| | $ | 4,857 |
| | $ | 5,147 |
|
|
| | | | | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2012 | | 2011 | | 2010 |
| Electric Generation – megawatthours (in millions): | | | | | |
| Ameren Missouri | 44.7 |
| | 48.8 |
| | 48.1 |
|
| Merchant Generation: | | | | | |
| Genco | 18.5 |
| | 22.0 |
| | 22.0 |
|
| AERG | 7.2 |
| | 7.0 |
| | 7.5 |
|
| Medina Valley | — |
| | 0.1 |
| | 0.1 |
|
| Subtotal | 25.7 |
| | 29.1 |
| | 29.6 |
|
| Ameren total | 70.4 |
| | 77.9 |
| | 77.7 |
|
| Price per ton of delivered coal (average) | $ | 36.63 |
| | $ | 33.79 |
| | $ | 32.91 |
|
| Source of energy supply: | | | | | |
| Coal | 65.1 | % | | 66.5 | % | | 65.7 | % |
| Nuclear | 12.4 |
| | 9.4 |
| | 8.9 |
|
| Hydroelectric | 1.1 |
| | 1.3 |
| | 1.6 |
|
| Natural gas | 2.7 |
| | 1.1 |
| | 1.0 |
|
| Purchased – Wind | 0.4 |
| | 0.3 |
| | 0.3 |
|
| Purchased – Other | 18.3 |
| | 21.4 |
| | 22.5 |
|
| | 100.0 | % | | 100.0 | % | | 100.0 | % |
|
| | | | | | | | | | | |
Electric Operating Statistics – Year Ended December 31, | 2013 | | 2012 | | 2011 |
| Electric Generation – Ameren Missouri – megawatthours (in millions) | 43.2 |
| | 44.7 |
| | 48.8 |
|
| Price per ton of delivered coal (average) – Ameren Missouri | $ | 36.19 |
| | $ | 34.21 |
| | $ | 30.57 |
|
| Ameren source of energy supply: | | | | | |
| Coal | 70.2 | % | | 65.1 | % | | 66.5 | % |
| Nuclear | 10.5 |
| | 12.4 |
| | 9.4 |
|
| Hydroelectric | 1.6 |
| | 1.1 |
| | 1.3 |
|
| Natural gas | 1.1 |
| | 2.7 |
| | 1.1 |
|
| Methane gas | 0.1 |
| | — |
| | — |
|
| Purchased – Wind | 0.4 |
| | 0.4 |
| | 0.3 |
|
| Purchased – Other | 16.1 |
| | 18.3 |
| | 21.4 |
|
| | 100.0 | % | | 100.0 | % | | 100.0 | % |
| | Gas Operating Statistics – Year Ended December 31, | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Natural Gas Sales (millions of dekatherms): | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | 6 |
| | 7 |
| | 7 |
| 8 |
| | 6 |
| | 7 |
|
| Commercial | 3 |
| | 3 |
| | 4 |
| 4 |
| | 3 |
| | 3 |
|
| Industrial | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
| Transport | | 6 |
| | 6 |
| | 5 |
|
| Subtotal | 10 |
| | 11 |
| | 12 |
| 19 |
| | 16 |
| | 16 |
|
| Ameren Illinois: | | | | | | | | | | |
| Residential | 49 |
| | 56 |
| | 60 |
| 62 |
| | 49 |
| | 56 |
|
| Commercial | 17 |
| | 21 |
| | 23 |
| 21 |
| | 17 |
| | 21 |
|
| Industrial | 5 |
| | 5 |
| | 7 |
| 6 |
| | 5 |
| | 5 |
|
| Other | 3 |
| | — |
| | — |
| |
| Subtotal | 74 |
| | 82 |
| | 90 |
| |
| Other: | | | | | | |
| Industrial | — |
| | — |
| | 1 |
| |
| Transport and other | | 87 |
| | 86 |
| | 80 |
|
| Subtotal | — |
| | — |
| | 1 |
| 176 |
| | 157 |
| | 162 |
|
| Ameren total | 84 |
| | 93 |
| | 103 |
| 195 |
| | 173 |
| | 178 |
|
| Natural Gas Operating Revenues (in millions) | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | |
| Residential | $ | 85 |
| | $ | 96 |
| | $ | 100 |
| $ | 102 |
| | $ | 85 |
| | $ | 96 |
|
| Commercial | 36 |
| | 41 |
| | 43 |
| 42 |
| | 36 |
| | 42 |
|
| Industrial | 8 |
| | 9 |
| | 10 |
| 8 |
| | 8 |
| | 9 |
|
| Other | 10 |
| | 10 |
| | 13 |
| |
| Transport and other | | 9 |
| | 10 |
| | 9 |
|
| Subtotal | $ | 139 |
| | $ | 156 |
| | $ | 166 |
| $ | 161 |
| | $ | 139 |
| | $ | 156 |
|
| Ameren Illinois: | | | | | | | | | | |
| Residential | $ | 547 |
| | $ | 588 |
| | $ | 649 |
| $ | 611 |
| | $ | 547 |
| | $ | 588 |
|
| Commercial | 172 |
| | 195 |
| | 223 |
| 185 |
| | 172 |
| | 195 |
|
| Industrial | 24 |
| | 30 |
| | 44 |
| 26 |
| | 24 |
| | 30 |
|
| Other | 43 |
| | 33 |
| | 37 |
| |
| Transport and other | | 25 |
| | 43 |
| | 33 |
|
| Subtotal | $ | 786 |
| | $ | 846 |
| | $ | 953 |
| $ | 847 |
| | $ | 786 |
| | $ | 846 |
|
| Other: | | | | | | |
| Industrial | $ | — |
| | $ | — |
| | $ | 4 |
| |
| Eliminate affiliate revenues | (1 | ) | | (1 | ) | | (6 | ) | (2 | ) | | (1 | ) | | (1 | ) |
| Ameren total | $ | 924 |
| | $ | 1,001 |
| | $ | 1,117 |
| $ | 1,006 |
| | $ | 924 |
| | $ | 1,001 |
|
| Peak day throughput (thousands of dekatherms): | | | | | | |
| Ameren Missouri | 139 |
| | 149 |
| | 167 |
| |
| Ameren Illinois | 1,061 |
| | 1,157 |
| | 1,227 |
| |
| Total peak day throughput | 1,200 |
| | 1,306 |
| | 1,394 |
| |
AVAILABLE INFORMATION
The Ameren Companies make available free of charge through Ameren’s website (www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, eXtensible Business Reporting Language (XBRL) documents, and any amendments to those reports filed with or furnished to 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 website maintained by the SEC (www.sec.gov). Ameren also uses its website 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 to and accessible at Ameren’s website.
The Ameren Companies also make available free of charge through Ameren’s website the charters of Ameren’s board of directors’ audit and risk committee, human resources committee, nominating and corporate governance committee, finance committee, and nuclear oversight and environmental 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 website, or any other website referenced in this report, is not incorporated by reference into this report.
Investors should review carefully the following material 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 further risks and uncertainties that are not presently known or that are not currently believed to be material that may adversely affect the 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.
The Ameren Companies are subject to extensive regulation of their businesses, which could adversely affect their results of operations, financial position, and liquidity.
The Ameren Companies are subject to, or affected by, extensive federal, state, and local 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 utility industries; rate and cost structure of utilities; operation of nuclear energy centers; 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. The Ameren Companies must address in their 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 the Ameren Companies’ businesses could require changes to their business planning and management of their businesses and could adversely affect their results of operations, financial position, and liquidity. Failure of the Ameren Companies to obtain adequate rates or regulatory approvals in a timely manner, failure to obtain necessary licenses or permits from regulatory authorities, new or modified laws, regulations, standards, interpretations, or other legal requirements, or increased compliance costs could adversely impact the Ameren Companies’ results of operations, financial position, and liquidity.
The electric and natural gas rates that Ameren Missouri and Ameren Illinois are allowed to charge are determined through regulatory proceedings, which are subject to intervention and appeal, and are subject to legislative actions, which are largely outside of their control. Any events that prevent Ameren Missouri or Ameren Illinois from recovering their respective costs or from earning appropriateadequate returns on their investments could adversely affect the Ameren Companies' results of operations, financial position, and liquidity.
The rates that Ameren Missouri and Ameren Illinois 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 industries are highlyextensively regulated. The utility rates charged to Ameren Missouri and Ameren Illinois 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, customer intervention, economic conditions, public policy, and social and political views. Decisions made by these governmental entities regarding rates are largely outside of Ameren Missouri’s and Ameren Illinois’ control. RegulatoryAmeren's utility operations are exposed to regulatory lag involved in filing and getting new rates approved could haveto varying degrees by jurisdiction, which, if unmitigated, has a material adverse effect on our results of operations, financial position, and liquidity. Rate orders are also subject to appeal, which creates additional uncertainty as to the rates Ameren Missouri and Ameren Illinois will ultimately be allowed to charge for their services.
Ameren Missouri electric and natural gas utility rates and Ameren Illinois natural gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Rates established in those proceedings for Ameren Missouri are primarily based on historical costs and revenues. RatesNatural gas rates established in those proceedings for Ameren Illinois may be based on historical or estimated future costs and revenues. Thus, the rates a utility is allowed to charge may not match its costs at any given time. Rates include an allowed rate of return on
investments determined by the regulators. Although rate regulation is premised on
providing a reasonablean opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judgedetermine that all the costs of Ameren Missouri and Ameren Illinois 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.
In years when capital investments and operations costs rise while customer usage declines, such as in 2012, Ameren Missouri and Ameren Illinois may not be able to earn the allowed return established by their regulators.state commissions. This could result in the deferral or elimination of planned capital investments, which reduceswould reduce the rate base investments from which the utility operations earn a rate of return on.return. Additionally, a period of increasing rates for our customers could result in additional regulatory and legislative actions, as well as competitive and political pressures, which could adversely affect the Ameren Companies' results of operations, financial position, and liquidity.
Through its participation in the performance-based formula ratemaking process established pursuant to the IEIMA, Ameren Illinois’ return on equity for its electric distribution business will be directly correlated to yields on United States treasury bonds. Additionally, Ameren Illinois will be subject to an annual ICC prudence review, and to the ICC's implementation of the IEIMA, and Ameren Illinois will be required to achieve performance objectives, increase capital spending levels, and meet job creation targets, which if not successfully completed or achievedtargets. Failure to meet these requirements could adversely affect Ameren Illinois' results of operations, financial position, and liquidity.
In 2012, Ameren Illinois elected to participateis participating in the performance-based formula ratemaking process established pursuant to the IEIMA for its electric distribution business. The ICC will annually reviewreviews Ameren Illinois’ performance-based rate filings under the IEIMA for reasonableness and prudency. If the ICC were to conclude that Ameren Illinois’ incurred costs were not prudently incurred, the ICC couldwould disallow recovery of such costs. Ameren is also subject to the ICC's implementation of the IEIMA's formula rates. After reviewing the ICC's IEIMA formula rate orders in 2012, Ameren Illinois believes that the ICC has incorrectly implemented the IEIMA. Ameren Illinois objects to the ICC's use of an average rate base as opposed to a year-end rate base in setting rates, to its treatment of accumulated deferred income taxes, and to the methods it used to calculate the equity portion of Ameren Illinois' capital structure and to calculate interest on the revenue requirement reconciliation and return on equity collar.
The return on equity component of the formula rate is equal to the average for the calendar year of the monthly yields of 30-year United States treasury bonds plus 580 basis points for years after 2012.points. Therefore, Ameren Illinois’ annual return on equity will beunder the formula ratemaking process for its electric distribution business is directly correlated to yields on United States treasurysuch bonds, which are outside of Ameren Illinois’ control.
Ameren Illinois willis also be subject to performance
standards. Failure to achieve the standards willwould result in a reduction in the company’s allowed return on equity calculated under the formula. The IEIMA provides for return on equity penalties totaling 30 basis points in 2013 through 2015, 34 basis points in 2016 through 2018, and 38 basis points in 2019 through 2022 if the performance standards are not met.
Between 2012 and 2021, Ameren Illinois will beis required to invest $625 million in capital expendituresprojects incremental to Ameren Illinois’ average electric delivery capital expendituresprojects for calendar
years 2008 through 2010 to modernize its distribution system. Ameren Illinois is subject to monetary penalties if 450 additional jobs in Illinois are not created in Illinois during the peak program year.
The formula ratemaking process would terminate if the average residential rate increases by more than 2.5% annually from June 2011 through May 2014. The average residential rate includes generation service, which is outside of Ameren Illinois’ control, as Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. If the performance-based formula rate process is terminated, Ameren Illinois would be required to establish future rates through a traditional rate proceeding with the ICC, which might not result in rates that produce a full or timely recovery of costs or an adequate return on investments. Unless it is extended, the IEIMA formula ratemaking process expires in 2017.
Customers’, legislators’ and regulators’ opinions of us are affected by our ability to provide reliable utility service to our customers. Failure to provide such reliable utility service could result in customers and regulators having a negative opinion of us, which, in turn, could adversely affect the Ameren Companies' results of operations, financial position, and liquidity.
Ameren’s utility subsidiaries provide utility service to 2.4 million electric customers and 0.9 million natural gas customers. Service interruptions due to failures of equipment or facilities as a result of severe or destructive weather or other causes, and the ability of Ameren Missouri and Ameren Illinois to promptly respond to such failures, can affect customer satisfaction. In addition to system reliability issues, the success of modernization efforts, such as those planned for Ameren Illinois’ electric and natural gas delivery systems, and other public actions of the Ameren Companies can affect customer satisfaction. Rate increases and volatility of rates can also affect customer satisfaction.
If customers, legislators or regulators have a negative opinion of us and our utility services, this could result in increased regulatory oversight of the Ameren Companies and could impact the returns on common equity we are allowed to earn. Additionally, negative opinions of the Ameren Companies could make it more difficult for our utilities to achieve favorable legislative or regulatory outcomes. Any of these consequences could adversely affect the Ameren Companies’ results of operations, financial position, and liquidity.
Energy conservation, energy efficiency, effortsdistributed generation, and other factors that reduce energy demand could adversely affect the Ameren Companies’ results of operations, financial position, and liquidity.
Regulatory and legislative bodies have proposed or introduced requirements and incentives to reduce energy consumption. Conservation and energy efficiency programs are designed to reduce energy demand. Unless there is a regulatory solution ensuring recovery, declining usage will result in an underrecoveryunder-recovery of fixed costs at our rate-regulated business.businesses. Ameren Missouri, even with the implementation of energy
efficiency programs under the MEEIA, is exposed to declining usage losses from energy efficiency efforts not related to its specific programs as well as distributed generation sources such as solar panels. Macroeconomic factors resulting in low economic growth or contraction within the Ameren Companies' service territories could also reduce energy demand.
We are subject to various environmental laws and regulations that require significantregulations. Significant capital expenditures.expenditures are required to achieve and maintain compliance with their standards. Failure to meet these standards could result in closure of facilities, increase ouralterations to the manner in which these facilities operate, increased operating costs, adversely affectadverse impacts to our results of operations, financial position, and liquidity, or expose usexposure to 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 operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and
regulations address emissions,emissions; water discharges and usage; impacts to air, land, and water, noise,water; noise; protected natural and cultural resources (such as wetlands, endangered species, and other protected wildlife, and archaeological 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.
We are also subject to liability under environmental laws that address the remediation of 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.materials or seek to compel remediation of environmental contamination or recover damages resulting from that contamination.
In addition to existing laws and regulations, including the Illinois MPS that applies to our energy centers in Illinois, theThe EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry.industry over time. These regulations could be particularly burdensome for certain companies, including Ameren Ameren Missouri, and AER, that operate coal-fired energy centers. These new regulations may be litigated, so the timing of their ultimate implementation and our required compliance is uncertain, as evidenced by the stay and remand of the CSAPR.uncertain.
Ameren is also subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. The EPA is engaged in an enforcement initiative to determine whether coal-fired energy centers failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the energy centers implemented modifications. Following the issuance of a Notice of Violation, inIn January 2011,
the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA’s complaint, as amended in October 2013, alleges that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States District Court granted, in part, Ameren Missouri’s motion to dismiss various aspects of the EPA’s penalty claims. The EPA’s claims for unspecified injunctive relief including requiring the installation of pollution control equipment, remain. Litigation ofTrial in this matter could take many years.is currently scheduled to begin in January 2015. An outcome in this matter adverse to Ameren Missouri 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.
In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at Genco's Newton energy center violated federal laws. Ameren and Genco are unable to predict the outcome of this matter and whether the EPA will address this Notice of Violation administratively or through
litigation.
Ameren, Ameren Missouri and AER have incurred and expect to incur significant costs related to environmental compliance and site remediation. New environmental regulations, revised 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 fines, or closure of facilities for Ameren and Ameren Missouri, and AER.Missouri. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive.expensive if the costs are not recovered through rates. As a result, environmental regulationslaws could also require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of plant assets. Although costsliquidity. Costs incurred by Ameren Missouri to ensure that its facilities are in compliance with environmental laws and regulations would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar cost recovery mechanism with respect to AER.proceeding. 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 probablymay require Ameren Ameren Missouri and AER to incur significant increases in capital expenditures and operating costs, which, if excessive and not recoverable through rate proceedings, could result in the closures of coal-fired energy centers, impairment of assets, or otherwise adversely affect our results of operations, financial position, and liquidity.
State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Impactsemissions. Potential impacts from any climate changesuch legislation or regulation 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-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, our emissionsEmissions of greenhouse gases vary among our energy centers, but coal-fired energy centers are significant sources of CO2. The enactment of a climate change law that restricts emissions of CO2 or requires energy centers to purchase allowances for CO2 emission could result in a significant riseincrease in rates for electricity, and thereby accordingly, in
household costs. 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 energy centers.
In June 2013, the Obama administration announced that it had directed the EPA to set CO2 emissions standards for both new and existing power plants. The EPA published proposed regulations in January 2014 that would set revised CO2 emissions standards for new electricity generating units. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In addition, the Obama administration directed the EPA to propose a CO2 emissions standard for existing power plants by June 2014 and to finalize such standards by June 2015.
Future federal andor state legislation or regulations that mandate limits on the emission of greenhouse gases would probablylikely result in significant increases in our capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, if Ameren Missouri requests recovery of these costs through rates, its regulators could deny some or all of these costs, or deferprevent timely recovery of them. Excessive costs to comply with future
legislation or regulations that are not recoverable through rate proceedings might force Ameren Ameren Missouri and AER to close some coal-fired energy centers earlier than planned, which couldwould lead to possible impairment of assets and reduced revenues. As a result, mandatorygreenhouse gas emission limits could have a material adverse impact on Ameren’s and Ameren Missouri’s and AER's results of operations, financial position, and liquidity.
The construction of, and capital improvements to, the Ameren Companies' electric and natural gas utility infrastructure and AER's energy centers 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 reasonablean adequate return on invested capital, any of which could result in higher costs and the closure of facilities.
The Ameren Companies expect to incur significant capital expenditures to comply with existing and known environmental regulations and to make investments in their electric and natural gas utility infrastructure and in AER's energy centers if they are owned by Ameren over the next five years.infrastructure. Ameren estimates it will incur up to $9.5$8.7 billion (Ameren Missouri - up to $3.8$3.5 billion; Ameren Illinois - up to $3.9 billion; AER - up to $0.4$3.7 billion; other - up to $1.4$1.5 billion) of capital expenditures during the period 20132014 through 2017.2018. These expensesestimates include construction expenditures, capitalized interest or allowance for funds used during construction, and capital expenditures for compliance with environmental standards and with the requirements of the IEIMA.construction.
Investments in Ameren’s rate-regulated operations are expected to be recoverable from ratepayers, but are subject to prudency reviews and regulatory lag. The recoverability of amounts expended in Ameren's Merchant Generation operations will depend upon market prices for capacity and energy.
The ability of the Ameren Companies to complete construction projects successfully and within projected 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 favorablereasonable terms, or other events beyond our control that could occur may materially affect the schedule, cost, and performance of these projects. With respect to capital expenditures for pollution control equipment, there is a risk that energy centers 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 pollution control equipment not be installed on time or perform as expected, the Ameren Companies could be subject to additional costs and to the loss of their investment in the project or facility. All of these risks may adversely affect the Ameren Companies’ results of operations, financial position, and liquidity.
As of December 31, 2012,2013, Ameren Missouri had capitalized $69 million of costs incurred to license additional nuclear generation at its Callaway energy site. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.
We may not be able to execute our electric transmission investment plans and realize the expected return on those investments.
Ameren, through ATXI and Ameren Illinois, is allocating significant additional capital resources to electric transmission investments. This allocation of capital resources is based on FERC's regulatory framework and a rate of return on common equity that is currently higher than allowed by our state commissions. However, the FERC regulatory framework and rate of return is subject to change and thechange. The regulatory framework may not be as favorable, or the rate of return may be lower, in the future. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. In 2013, a FERC administrative law judge issued an initial decision stating that the current 11.14% allowed rate of return for New England transmission owners was unjust and unreasonable. FERC has not issued its final order in this case, and it is under no deadline to do so. In November 2013, a complaint case was filed with FERC seeking a reduction in the allowed return on common equity, as well as a limit on the common equity ratio, under the MISO tariff. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also result in a refund for transmission service revenues earned after the filing of the complaint case in November 2013. As in the New England transmission owners' case, discussed above, FERC has not issued an order in this case, and it is under no deadline to do so.
A significant numberportion of our planned electric transmission investments consists of three separate projects to be constructed by ATXI, which have been approved by MISO as multi-value projects. The largest of the three separate multi-value projects to be constructed by ATXI.is the Illinois Rivers project. The total investment in these three projects is expected to be more than $1.3 billion with the$1.4 billion. The last of these projects is expected to be
completed in 2019. AnyA failure by Ameren to complete all of these three projects as designed on time and within projected cost estimates could adversely affect our results of operations, financial position, and liquidity. Future investments may be affected by changes in
FERC policy regardinghas issued multiple orders, which are subject to ongoing litigation, eliminating the utilities' right of first refusal for electric utilities to construct certain new transmission projects within their service territory. InIf these orders are upheld by the future,courts, Ameren may not be ablemight need to invest incompete to build certain future electric transmission projects in its subsidiaries' service territories. Such competition could prevent Ameren from investing in future electric transmission projects to the extent desired.
Our counterparties may not meet their obligations to us, and Ameren affiliates may not meet their obligations to each other.
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, borrowing from the money pools, 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. Ameren (parent) may itself have to fulfill its subsidiary obligations based on guarantees it has entered into on behalf of its subsidiaries. See Note 14 - Related Party Transactions under Part II, Item 8 for information on Ameren (parent) guarantees.
Increasing costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits could 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, 2012, its investment performance in 2012, and its pension funding policy, Ameren expects to make annual contributions of $60 million to $150 million in each of the next five years, with aggregate estimated contributions of $550 million. We expect Ameren Missouri’s and Ameren Illinois’ portion of the future funding requirements to be 50% and 40%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, 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 generation, transmission and distribution facilities are subject to operational risks that could adversely affect our results of operations, financial position, and liquidity.
The Ameren Companies’ financial performance depends on the successful operation of electric generation, transmission, and distribution facilities. Operation of electric generation, transmission, and distribution facilities involves many risks, including:
facility shutdowns due to operator error or a failure of equipment or processes;
longer-than-anticipated maintenance outages;
older generating equipment that may require significant expenditures to keep it operatingoperate at peak efficiency;
disruptions in the delivery of fuel or lack of adequate
inventories, including ultra-low-sulfur coal used for Ameren Missouri’s compliance with environmental regulations;
lack of water through low river levels or other causes, required for cooling plant operations;
labor disputes;
inability to comply with regulatory or permit requirements, including those relating to environmental contamination;laws;
disruptions in the delivery of electricity including impacts on us orthat impact our customers;
handling and storage of fossil-fuel combustion byproducts, such as CCR;
unusual or adverse weather conditions, including severe storms, droughts, floods, tornadoes, solar flares, and tornadoes;electromagnetic pulses;
a workplace accident that might result in injury or loss of life, extensive property damage, or environmental damage;
cybersecurity risk, including loss of operational control of our energy centers and our electric and natural gas transmission and distribution systems and/or loss of data, such as utility customer data, account information, and intellectual property through insider or outsider actions;
catastrophic events such as fires, explosions, pandemic health events, or other similar occurrences;
limitations on amounts of insurance available to cover losses that might arise in connection with operating our electric generation, transmission, and distribution facilities; and
other unanticipated operations and maintenance expenses and liabilities.
Our natural gas distribution and storage activities involve numerous risks that may result in accidents and other operating risks and costs that could 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, mechanical problems and cybersecurity risks, 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 for 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.
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, including FERC Reliability Standards. FERC can 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 energy centers, are subject to mandatory NERC reliability standards, including cybersecurity 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 could incur substantial monetary penalties and other sanctions, which could adversely affect our results of operations, financial position, and liquidity. FERC also conducts audits and reviews of Ameren Missouri's, Ameren Illinois', and ATXI's accounting records to assess the accuracy of its formula rate-making process and has the ability to require retroactive refunds to customers for previously billed amounts, with interest.
Even though agreements have been reached with the state of Missouri and the FERC, the breach of the upper reservoir of Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center could continue to have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, liquidity, and financial condition.
In December 2005, there was a breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. Ameren Missouri has settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident.
Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Currently, Ameren Missouri has filed separate lawsuits against two different liability insurance providers claiming that the insurance companies breached their duty to indemnify Ameren Missouri for the losses experienced from the incident. Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity could be adversely affected if Ameren Missouri’s remaining liability insurance claims of $68 million as of December 31, 2012, are not paid by insurers.
Ameren's Merchant Generation energy centers must compete for the sale of energy and capacity, which exposes that business to price risks.
All of Ameren's Merchant Generation energy centers compete for the sale of energy and capacity in the competitive energy markets.
To the extent that electricity generated by these energy centers is not under a fixed-price contract to be sold, the revenues and results of operations of these Merchant Generation 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 over both the short and long term. For example,
market prices for power have decreased over the past several years. Demand for electricity and fuel can fluctuate dramatically, creating periods of substantial undersupply or oversupply. During periods of 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 and by 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 affect Ameren’s results of operations, financial condition and liquidity.
Any unhedged forecasted generation will be exposed to market prices at the time of sale. As a result, any new physical or financial power sales may be at price levels lower than previously experienced and lower than the value of existing hedged sales.
Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:
current and future delivered market prices for natural gas, coal, and related transportation costs;
current and forward prices for the sale of electricity;
current and future prices for emission allowances that may be required to operate the fossil-fuel-fired electric energy centers in compliance with environmental laws and permits;
the extent of additional supplies of electric energy from current competitors or new market entrants;
the regulatory and market structures developed for evolving Midwest energy markets, including a capacity market in MISO;
changes enacted by the Illinois legislature, the ICC, the IPA, or other government agencies with respect to power procurement procedures;
the potential for reregulation of generation in some states;
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;
the growth rate or decline in electricity usage as a result of population changes, regional economic conditions, and the implementation of energy-efficiency and conservation programs;
climate conditions in the Midwest market and major natural disasters; and
environmental laws and regulations or delays in their effective dates.
There is substantial uncertainty concerning the manner, timing, and terms of our anticipated exit from the Merchant Generation business.
In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. However, Ameren's date and method of exit from the Merchant Generation business are currently uncertain. Exit strategies may include the sale of all or parts of Ameren's Merchant Generation business and the restructuring of all or a portion of Ameren's equity position in Genco. Once a plan of disposal is finalized, Ameren's implementation of that plan may result in long-lived asset impairments, disposal-related losses, contingencies, reduction of existing deferred tax assets, and other consequences that are currently unknown to Ameren.
Ameren's Merchant Generation business is experiencing a period of declining operating revenues and higher costs with limited available sources of external liquidity, and internal sources of liquidity available only at Ameren's discretion, which could be withheld by Ameren. Merchant Generation, including Genco, may require liquidity support from Ameren, which could adversely affect Ameren's results of operations, financial position, and liquidity.
Based on projections as of December 31, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco's indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control. If a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. It is probable that during 2013 Genco will seek mid-month liquidity from Ameren to support the timing of Genco's cash flows. Ameren may decide not to provide funding to Genco should a financing need arise in 2013 or in the future. Genco also has significant debt maturities beginning in 2018. If Genco is unable to meet its liquidity needs, this could result in Genco accelerating asset sales, or restructuring. Genco expects to sell certain of its long-lived assets, either individually or through its put option with AERG, but the proceeds realized from any asset sale may not be adequate to satisfy Genco's liquidity needs.
Ameren's December 2012 decision that the Merchant Generation segment is no longer a core component of its future strategy could adversely affect Ameren's results of operations, financial position, and liquidity. Ameren has begun planning to reduce, and ultimately to eliminate, the reliance of the Merchant Generation segment, including Genco, on Ameren's financial support and shared service support. Ameren's exit date from the Merchant Generation segment is uncertain. By requiring the
Merchant Generation segment to duplicate support services, Ameren may reduce the synergies between its business segments. Further, counterparties may not extend credit to the Merchant Generation segment, which could limit Merchant Generation revenue opportunities and may result in a need for additional liquidity to operate the business. Also, Ameren has supplied guarantees to support Marketing Company's creditworthiness with counterparties. Under these guarantees, Ameren may have to fulfill Marketing Company obligations if Marketing Company becomes unable to satisfy the counterparty obligation with its own liquidity. Ameren may also be required to supply liquidity and to contribute capital to AERG should Genco exercise its put option agreement relating to three natural-gas-fired energy centers. See Note 14 - Related Party Transactions under Part II, Item 8, of this report for additional information about the put option agreement and Ameren parent guarantees.
Ameren Missouri’s ownership and operation of a nuclear energy center creates business, financial, and waste disposal risks.
Ameren Missouri’s ownership of the Callaway energy center subjects it to the risks of nuclear generation, which include the following:
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;
the lack of a permanent waste storage site;
limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with the Callaway energy center or other United States nuclear operations;
uncertainties with respect to contingencies and retrospective premium assessments relating to claims at the Callaway energy center or any other United States nuclear energy center;
public and governmental concerns overabout the adequacy of security at nuclear energy centers;
uncertainties with respect to the technological and financial aspects of decommissioning nuclear energy centers at the end of their licensed lives (Ameren Missouri has submitted an application with the NRC to extend the Callaway energy center’s operating license from 2024 to 2044);lives;
limited availability of fuel supply; and
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 energy centers. In the event of noncompliance, the NRC has the authority to impose fines or to 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 energy centers such as Ameren Missouri’s. In addition, if a serious nuclear incident were to occur, it could have a material but indeterminable adverse effect on Ameren Missouri’s results of operations, financial condition, and
liquidity. A major incident at a nuclear energy center 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 energy center 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. For example, the earthquake in 2011 that affected nuclear energy centers in Japan has resulted in regulatory changes in the United States, and may result in future regulatory changes that may impose additional costs on all United States nuclear energy centers.centers in the United States. Specific to seismic risk, the NRC may require Callaway to further evaluate the impact of an earthquake on its operations, which could lead to the installation of additional capital equipment to comply with revised NRC standards.
Our energy risk management strategiesnatural gas distribution and storage activities involve numerous risks that may not be effectiveresult in managing fuelaccidents and electricity procurementother operating risks and pricingcosts that could 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, mechanical problems and cybersecurity risks, which could cause substantial financial losses. In addition, these risks could result in unanticipated liabilities or increased volatility in our earningsserious injury, loss of human life, significant damage to property, environmental pollution, and cash flows.
We are exposed to changes in market prices for natural gas, fuel, power, emission allowances, renewable energy credits, and transmission congestion. Prices for natural gas, fuel, power, emission allowances and renewable energy credits may fluctuate substantially over relatively short periods of time, and at other times exhibit 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 exposureimpairment of our operations, which in turn could lead to substantial losses for 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, business centers, industrial sites, and other public gathering places, could increase the level of damages resulting 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 maythese risks. The occurrence of any of these events not be able to execute our risk management strategies, whichfully covered by insurance could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices canmaterially adversely affect our results of operations, financial position, and liquidity.
Our facilitiesWe are considered criticalsubject 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, including with respect to mandatory NERC reliability standards. FERC can 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 energy infrastructurecenters, are subject to mandatory NERC reliability standards, including cybersecurity standards. Compliance with these mandatory reliability standards may subject the Ameren Companies to higher operating costs and may thereforeresult in increased capital expenditures. If the Ameren Companies were found not to be targets of acts of terrorism.
Like other electricin compliance with these mandatory reliability standards or FERC statutes, rules and natural gas utilitiesorders, the Ameren Companies could incur substantial monetary penalties and other merchant electric generators, our energy centers, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities, including cybersecurity attacks, which 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,sanctions, which could adversely affect on our results of operations, financial position, and liquidity. FERC also conducts audits and reviews of Ameren Missouri's, Ameren Illinois', and ATXI's accounting records to assess the accuracy of its formula rate-making process and has the ability to require retroactive refunds to customers for previously billed amounts, with interest.
Even though agreements were reached with the state of Missouri and FERC, the breach of the upper reservoir of Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center could continue to have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, liquidity, and financial condition.
In December 2005, there was a breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. Ameren Missouri settled with the state of Missouri and FERC all issues associated with the December 2005 Taum Sauk incident.
Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles.
Ameren Missouri filed separate lawsuits against two different liability insurance providers claiming that the insurance companies breached their duty to indemnify Ameren Missouri for the losses experienced from the incident. Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity could be adversely affected if Ameren Missouri’s remaining liability insurance claims of $68 million as of December 31, 2013, are not paid by insurers.
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 userely on short-term and long-term debt as a significant sourcesources of liquidity and funding for capital requirements not satisfied by our operating cash flow including requirements relatedas well as to future environmental compliance and capital expenditures required by the IEIMA. As a result of rising costs and increased capital and operations and maintenance expenditures, coupled with regulatory lag, we expect to continue to rely on short-term andrefinance long-term debt financing.debt. The inability to raise debt or equity capital on favorablereasonable terms, or at all, could negatively affect our ability to maintain and to expand our businesses. After assessing our current operating performance, liquidity, and credit ratings, we believe that Ameren and its rate-regulated businesses will continue to have access to the capital markets. However, eventsEvents beyond our control, such as a recession or extreme volatility in globalthe debt, or equity, capital andor credit markets, 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 our ability to draw on bank credit facilities. Based on projections as of December 31, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. An inability to raise debt could adversely impact Genco's liquidity. Any adverse change in Ameren's or in its subsidiaries'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 natural 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's subsidiaries, such as ATXI, 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 subsidiaries with needed capital. In addition, borrowings directly from Ameren and from the utility and non-state-regulated subsidiary money pools are subject to Ameren’s control and any borrowings are dependent on consideration by Ameren of the facts and circumstances existing at the time of the borrowing request.
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 and cash payments and receipts under the tax allocation agreement) 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.
Dynegy’s or its subsidiaries' failure to satisfy certain of their indemnity and other obligations to Ameren in connection with the divestiture of New AER to IPH could have a material adverse impact on Ameren’s results of operations, financial position or liquidity.
On December 2, 2013, Ameren completed the divestiture of New AER to IPH. The transaction agreement between Ameren and IPH requires Ameren, for up to 24 months after the closing of the divestiture of New AER, to maintain its financial obligations in existence as of the date of the closing under all credit support arrangements or obligations with respect to New AER and its subsidiaries. Ameren must also provide any additional credit support that may be contractually required pursuant to any of the contracts of New AER, and its subsidiaries as of the closing. IPH, New AER and its subsidiaries and Dynegy have agreed to indemnify Ameren for certain losses relating to this credit support. IPH’s indemnification obligations are secured by certain AERG and Genco assets. However, these indemnification obligations and security interests might not cover all losses incurred by Ameren in connection with this credit support. In addition, Dynegy emerged from its Chapter 11 bankruptcy case on October 1, 2012, and, as of December 31, 2013, Dynegy’s credit ratings were sub-investment grade. IPH, New AER and its subsidiaries also do not have investment grade credit ratings. Dynegy, IPH, New AER, or their subsidiaries might not be able to pay their indemnity and other obligations under the transaction agreement, Marketing Company’s note to Ameren, or Dynegy’s limited guarantee to Ameren, which could have a material adverse impact on Ameren’s results of operations, financial position, and liquidity. As of December 31, 2013, the balance of the Marketing Company note to Ameren was $18 million. As of December 31, 2013, Ameren provided $190 million in guarantees and letters of credit totaling $11 million relating to its credit support of New AER.
Government challenges to the tax positions taken by the Ameren Companies, as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions could adversely affect the Ameren Companies’ results of operations and cash flows.
The Ameren Companies are required to make judgments in order to estimate their obligations to taxing authorities. These obligations can include income tax and taxes other than income tax, many of which involve complex matters that ultimately could be determined by the courts. These judgments include reserves for potential adverse outcomes for tax positions that may be challenged by tax authorities. The Ameren Companies also estimate their ability to use tax benefits, including those in the form of carryforwards and tax credits that are recorded as deferred tax assets on their balance sheets. A disallowance of these tax benefits could have a material adverse impact on our results of operation, financial position, and liquidity.
The Ameren Companies’ operations are subject to acts of sabotage, war, terrorism, cyber attacks, and other
intentionally disruptive acts.
Like other electric and natural gas utilities, our energy centers, fuel storage facilities, transmission and distribution facilities, and information systems may be targets of terrorist activities, including cyber attacks, which could disrupt 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 adversely affect our results of operations, financial position, and liquidity.
A security breach of the Ameren Companies’ physical assets or information systems could affect the reliability of the transmission and distribution system, disrupt electric generation, and/or subject the Ameren Companies to financial harm associated with theft or inappropriate release of certain types of information, including sensitive customer and employee data. If a significant breach occurred, the reputation of the Ameren Companies could be adversely affected, customer confidence could be diminished, and/or the Ameren Companies could be subject to legal claims, any of which could result in a significant decrease in revenues or significant additional costs for rectifying the impacts of such a breach. The Ameren Companies’ use of smart meters throughout their service territories may increase the risk of damage from an intentional disruption of the system by third parties. In addition, new or updated security regulations could require changes in current measures taken by the Ameren Companies and could adversely affect their results of operations, cash flows, and financial position.
Increasing costs associated with our defined benefit retirement and postretirement plans, health care plans, and other employee benefits could adversely affect our 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 customers' rates and our plan 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, 2013, its investment performance in 2013, and its pension funding policy, Ameren expects to make annual contributions of $20 million to $100 million in each of the next five years, with aggregate estimated contributions of $270 million. We expect Ameren Missouri’s and Ameren Illinois’ portion of the future funding requirements to be 52% and 47%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, changes in our assumptions, 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 financial position and liquidity.
Failure to retain and attract key officers and other skilled professional and technical employees could adversely affect 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 workforce is nearing retirement, including many employees with specialized skills such as maintaining and servicing our electric and natural gas infrastructure and operating our energy centers.
| |
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
ITEM 2.PROPERTIES
For information on our principal properties, see the energy center 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 a 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 the capability of our Ameren Missouri energy centers is anticipated to be at the time of our expected 20132014 peak summer electrical demand:
|
| | | | |
| Primary Fuel Source | Energy Center | Location | Net Kilowatt Capability(a) |
Ameren Missouri: | | | |
| Coal | Labadie | Franklin County, Mo.Missouri | 2,374,000 |
|
| | Rush Island | Jefferson County, Mo.Missouri | 1,182,000 |
|
| | Sioux | St. Charles County, Mo.Missouri | 972,000 |
|
| | Meramec | St. Louis County, Mo.Missouri | 833,000831,000 |
|
| Total coal | | | 5,361,0005,359,000 |
|
| Nuclear | Callaway | Callaway County, Mo.Missouri | 1,194,0001,193,000 |
|
| Hydroelectric | Osage | Lakeside, Mo.Missouri | 240,000 |
|
| | Keokuk | Keokuk, Ia.Iowa | 140,000 |
|
| Total hydroelectric | | | 380,000 |
|
| Pumped-storage | Taum Sauk | Reynolds County, Mo.Missouri | 440,000 |
|
| Oil (CTs) | Meramec | St. Louis County, Mo.Missouri | 54,000 |
|
| | Fairgrounds | Jefferson City, Mo.Missouri | 54,000 |
|
| | Mexico | Mexico, Mo.Missouri | 53,000 |
|
| | Moberly | Moberly, Mo.Missouri | 53,000 |
|
| | Moreau | Jefferson City, Mo.Missouri | 53,000 |
|
| | Howard Bend | St. Louis County, Mo.Missouri | 39,000 |
|
| Total oil | | | 306,000 |
|
| Natural gas (CTs) | Audrain(b) | Audrain County, Mo.Missouri | 592,000600,000 |
|
| | Venice(c) | Venice, Ill.Illinois | 487,000 |
|
| | Goose Creek | Piatt County, Ill.Illinois | 426,000432,000 |
|
| | Pinckneyville | Pinckneyville, Ill.Illinois | 312,000316,000 |
|
| | Raccoon Creek | Clay County, Ill.Illinois | 296,000300,000 |
|
| | Kinmundy(c) | Kinmundy, Ill.Illinois | 206,000 |
|
| | Peno Creek(b)(c) | Bowling Green, Mo.Missouri | 188,000 |
|
| | Meramec(c) | St. Louis County, Mo.Missouri | 48,00044,000 |
|
| | Kirksville | Kirksville, Mo.Missouri | 12,00013,000 |
|
| Total natural gas | | | 2,567,0002,586,000 |
|
| Methane gas (CTs) | Maryland Heights | Maryland Heights, Mo.Missouri | 8,000 |
|
| Total Ameren and Ameren Missouri | | | 10,256,000 |
|
Merchant Generation: | | | |
Genco: | | | |
Coal | Newton | Newton, Ill. | 1,215,000 |
|
| Joppa (EEI)(d)
| Joppa, Ill. | 1,002,000 |
|
| Coffeen | Coffeen, Ill. | 895,000 |
|
Total coal | | | 3,112,000 |
|
Natural gas (CTs) | Grand Tower | Grand Tower, Ill. | 478,000 |
|
| Elgin | Elgin, Ill. | 460,000 |
|
| Gibson City(c)
| Gibson City, Ill. | 228,000 |
|
| Joppa 7B | Joppa, Ill. | 110,000 |
|
| Joppa (EEI)(d)
| Joppa, Ill. | 74,000 |
|
Total natural gas | | | 1,350,000 |
|
Total Genco | | | 4,462,000 |
|
AERG: | | | |
Coal | E.D. Edwards | Bartonville, Ill. | 650,000 |
|
| Duck Creek | Canton, Ill. | 410,000 |
|
Total AERG | | | 1,060,000 |
|
Total Merchant Generation | | | 5,522,000 |
|
Total Ameren | | | 15,778,00010,272,000 |
|
| |
| (a) | Net kilowatt capability is the generating capacity available for dispatch from the energy center into the electric transmission grid. |
| |
| (b) | There are economic development lease arrangements applicable to these CTs. |
| |
| (c) | These CTs have the capability to operate on either oil or natural gas (dual fuel). |
| |
(d) | Genco owns an 80% interest in EEI. This table reflects the full capability of EEI’s facilities. |
The following table presents electric and natural gas utility-related properties for Ameren Missouri and Ameren Illinois as of December 31, 20122013:
| | | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois |
Circuit miles of electric transmission lines(a) | 2,956 |
| | 4,506 |
| 2,956 |
| | 4,548 |
|
| Circuit miles of electric distribution lines | 32,967 |
| | 45,746 |
| 33,076 |
| | 46,011 |
|
| Circuit miles of electric distribution lines underground | 23 | % | | 15 | % | 23 | % | | 15 | % |
| Miles of natural gas transmission and distribution mains | 3,282 |
| | 18,137 |
| 3,297 |
| | 18,190 |
|
| Propane-air plants | 1 |
| | — |
| |
| Underground gas storage fields | — |
| | 12 |
| — |
| | 12 |
|
| Billion cubic feet of total working capacity of underground gas storage fields | — |
| | 24 |
| |
| Total working capacity of underground gas storage fields in billion cubic feet | | — |
| | 24 |
|
| |
| (a) | ATXI and EEI ownowns 29 miles and 42 miles of transmission lines respectively, not reflected in this table. |
Our other properties include office buildings, warehouses, garages, and repair shops.
With only a few exceptions, we have fee title to all principal
energy centers 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 to certain permitted liens and judgment liens). The exceptions are as follows:
A portion of Ameren Missouri’s Osage energy center reservoir, certain facilities at Ameren Missouri’s Sioux energy center, most of Ameren Missouri’s Peno Creek and Audrain CT energy centers, certain substations, and most transmission and distribution lines and natural 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 Ameren Missouri’s energy centers and other properties are located.
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 Ameren Missouri’s Keokuk energy center is located.
Substantially all of the properties and plant of Ameren Missouri and Ameren Illinois are subject to the first liens of the indentures securing their mortgage bonds.
Ameren Missouri has conveyed most of its Peno Creek CT energy center to the city of Bowling Green, Missouri, and leased the energy center back from the city through 2022. Under the terms of this capital lease, Ameren Missouri is responsible for all operation and maintenance for the energy center. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the lease, at which time the property and plant will become subject to the lien of any outstanding Ameren Missouri first mortgage bond indenture.
Ameren Missouri operates a CT energy center located in Audrain County, Missouri. Ameren Missouri has rights and obligations as lessee of the CT energy center under a long-term lease with Audrain County. The lease will expire on December 1, 2023. Under the terms of this capital lease, Ameren Missouri is responsible for all operation and maintenance for the energy center. Ownership of the energy center will transfer to Ameren Missouri at the expiration of the lease, at which time the property and plant will become subject to the lien of any outstanding Ameren Missouri first mortgage bond indenture.
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. Material legal and administrative proceedings, which are discussed in Note 2 -– Rate and Regulatory Matters and Note 15 -– Commitment and Contingencies under Part II, Item 8, of this report and are incorporated herein by reference, include the following:
appeal of the MoPSC's April 2011 FAC prudence review order and completion of the current FAC prudence review;
Ameren Missouri's appeal of the MoPSC's December 2012 electric rate order;
Ameren Illinois' appeal of the ICC's 2012December 2013 electric distribution rate orders in its initial and update IEIMA filings;
natural gas rate proceeding for Ameren Illinois pending before the ICC;order;
FERC litigation to determine wholesale distribution revenues for five of Ameren Illinois' wholesale customers;
Complaint cases filed by Noranda and 37 residential customers with the MoPSC in February 2014 requesting a reduction to Ameren Missouri's electric rates, including a reduction to its allowed return on equity, and certain rate design changes;
Entergy's rehearing request of a FERC May 2012 order requiring Entergy to refund to Ameren Missouri additional charges Ameren Missouri paid under an expired power purchase agreement;
Ameren Illinois' request for rehearing of a FERCFERC's July 2012 orderand June 2013 orders regarding the inclusion of acquisition premiums in Ameren Illinois' electric transmission rates;
ATXI's request for a certificate of public convenience and necessity and project approval from the ICC for the Illinois Rivers project;
the EPA's Clean Air Act-related litigation filed against Ameren Missouri, NSR investigations at Genco and AERG, and the Notice of Violation for alleged permitting violations at Genco;Missouri;
remediation matters associated with former MGP and waste disposal sites of the Ameren Companies;
litigation associated with the breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center;
| |
• | litigation alleging that the CO2 emissions from several industrial companies, including Ameren Missouri, Genco,
|
and AERG, created atmospheric conditions that intensified Hurricane Katrina;
Ameren Illinois' receipt of tax liability notices relating to prior-period electric and natural gas municipal taxes; and
asbestos-related litigation associated with Ameren, Ameren Missouri, and Ameren Illinois; and
Merchant Generation's challenge before the Informal
Conference Board of the Illinois Department of Revenue regarding the State's position that EEI did not qualify for manufacturing tax exemptions for 2010 transactions.Illinois.
| |
| ITEM 4. | MINE SAFETY DISCLOSURES |
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 20122013, all positions and offices held with the Ameren Companies as of December 31, 2012 (except as otherwise noted below),February 14, 2014, 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. References to “Ameren Illinois companies” below refers to CIPS, CILCO and IP collectively prior to the Ameren Illinois Merger and to Ameren Illinois following the Ameren Illinois Merger.
AMEREN CORPORATION:
|
| | | | |
| Name | Age | | Positions and Offices Held |
| Thomas R. Voss | 6566 |
| | Chairman President and Chief Executive Officer, and Director |
Voss joined Ameren Missouri in 1969. He was elected senior vice president of Ameren Missouri, CIPS, and Ameren Services in 1999, 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 Ameren Missouri, CIPS, CILCO and IP. In 2007, Voss was elected chairman, president and chief executive officer of Ameren Missouri, and relinquished his positions at CIPS, CILCO and IP in 2007.Missouri. 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 additional position of chairman of the board. He has been a member of the Ameren board since 2009. Voss relinquished his position as president of Ameren, effective February 14, 2014, and will relinquish his position as chief executive officer of Ameren, effective April 24, 2014, and will retire as chairman and member of the Ameren board, effective July 1, 2014. |
| | | | |
Martin J. Lyons, Jr.Warner L. Baxter | 4652 |
| | Executive Vice President (Effective January 1, 2013) and Chief Financial Officer |
Lyons joined Ameren, Ameren Missouri, CIPS, and Ameren Services in 2001 as controller. He was elected controller of CILCO in 2003. He was also elected vice president of Ameren, Ameren Missouri, CIPS, CILCO, and Ameren Services in 2003 and vice president and controller of IP in 2004. In 2007, his positions at Ameren Missouri were changed to vice president and principal accounting officer. In 2008, Lyons was elected senior vice president and principal accounting officer of the Ameren companies. In 2009, Lyons was also elected chief financial officer of the Ameren companies. Following the Ameren Illinois Merger in 2010, Lyons remained senior vice president, chief financial officer and principal accounting officer of Ameren Illinois. Effective January 1, 2013, Lyons was elected executive vice president and chief financial officer of the Ameren companies, and relinquished his duties as principal accounting officer. |
| | | |
Gregory L. Nelson | 55 |
| | Senior Vice President, General Counsel and Secretary |
Nelson joined Ameren Missouri in 1995 as a manager in the tax department and assumed a similar position with Ameren Services in 1998. Nelson was elected vice president and tax counsel of Ameren Services in 1999 and vice president of Ameren Missouri, CIPS, and CILCO in 2003 and of IP in 2004. In 2010, Nelson was elected vice president, tax and deputy general counsel of Ameren Services. He remained vice president of Ameren Missouri, CIPS, CILCO, and IP. Following the Ameren Illinois Merger in 2010, Nelson remained vice president at Ameren Illinois. In 2011, Nelson was elected to the positions of senior vice president, general counsel and secretary of the Ameren companies. |
| | | |
Bruce A. Steinke | 51 |
| | Senior Vice President, Finance and Chief Accounting Officer (Effective January 1, 2013) |
Steinke joined Ameren Services in 2002 as a manager in the controller's department and head of investor relations. In 2008, he was elected vice president and controller of Ameren, CIPS, CILCO, IP and Ameren Services. In 2009, Steinke relinquished his positions at CIPS, CILCO and IP. Effective January 1, 2013, Steinke was elected senior vice president, finance and chief accounting officer of the Ameren companies. |
| | | |
Jerre E. Birdsong | 58 |
| | Vice President and Treasurer |
Birdsong joined Ameren Missouri in 1977 and was elected treasurer of Ameren Missouri in 1993. He was elected treasurer of Ameren, CIPS and Ameren Services in 1997. In addition to being treasurer, in 2001, Birdsong was elected vice president at Ameren, Ameren Missouri, CIPS, and Ameren Services. Additionally, he was elected vice president and treasurer of CILCO in 2003 and of IP in 2004. Following the Ameren Illinois Merger in 2010, Birdsong, remained vice president and treasurer at Ameren Illinois. Effective February 1, 2013, Birdsong retired from the Ameren companies. |
SUBSIDIARIES:
|
| | | | |
Name | Age | | Positions and Offices Held |
Warner L. Baxter | 51 |
| | Chairman, President and Chief Executive Officer (Ameren Missouri)Director |
Baxter joined Ameren Missouri in 1995 as assistant controller. He was elected senior vice president, finance, of Ameren, Ameren Missouri, CIPS, and Ameren Services in 2001 and of CILCO in 2003.1995. Baxter was elected to the positions of executive vice president and chief financial officer of Ameren, Ameren Missouri, CIPS, CILCO and Ameren Services in 2003 and of IP in 2004. He was elected chairman, president, chief executive officer and chief financial officer of Ameren Services in 2007. In 2009, Baxter was elected chairman, president and chief executive officer of Ameren Missouri; at that time, he relinquished his other positions. Baxter became president of Ameren and a member of the Ameren board, effective February 14, 2014, and will succeed Voss as chief executive officer of Ameren, effective April 24, 2014. The Ameren board expects that Baxter will succeed Voss as chairman of the board. |
| | | | |
| Martin J. Lyons, Jr. | 47 |
| | Executive Vice President and Chief Financial Officer |
| Lyons joined Ameren in 2001. In 2008, Lyons was elected senior vice president and principal accounting officer of the Ameren Companies. In 2009, Lyons was also elected chief financial officer of the Ameren Companies. In 2013, Lyons was elected executive vice president and chief financial officer of the Ameren Companies, and relinquished his duties as principal accounting officer. |
| | | |
| Gregory L. Nelson | 56 |
| | Senior Vice President, General Counsel and Secretary |
| Nelson joined Ameren Missouri in 1995. Nelson was elected vice president and tax counsel of Ameren Services in 1999 and vice president of Ameren Missouri, CIPS, and CILCO in 2003 and of IP in 2004. In 2010, Nelson was elected vice president, tax and deputy general counsel of Ameren Services. He remained vice president of Ameren Missouri and the Ameren Illinois companies. In 2011, Nelson was elected to the positions of senior vice president, general counsel and secretary of the Ameren Companies. |
| | | |
| Bruce A. Steinke | 52 |
| | Senior Vice President, Finance and Chief Accounting Officer |
| Steinke joined Ameren Services in 2002. In 2008, he was elected vice president and controller of Ameren, the Ameren Illinois companies and Ameren Services. In 2009, Steinke relinquished his positions at the Ameren Illinois companies. In 2013, Steinke was elected senior vice president, finance and chief accounting officer of the Ameren Companies. |
SUBSIDIARIES:
|
| | | | |
| Name | Age | | Positions and Offices Held |
| Maureen A. Borkowski | 5556 |
| | Chairman, President and Chief Executive Officer (ATXI) |
| Borkowski joined Ameren Missouri in 1981. She left the company in 2000 before rejoining Ameren in 2005 as vice president, transmission, of Ameren Services. In 2011, Borkowski was elected chairman, president and chief executive officer of ATXI. In 2011, she was also elected senior vice president, transmission, of Ameren Services. |
| | | | |
| Daniel F. Cole | 5960 |
| | Chairman, President and Chief Executive Officer (Ameren Services) |
Cole joined Ameren Missouri in 1976. He was elected senior vice president of Ameren Missouri and Ameren Services in 1999 and of CIPS in 2001. 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 Services and remained senior vice president of Ameren Missouri CIPS, CILCO and IP. Following the Ameren Illinois Merger in 2010, Cole remained senior vice president at Ameren Illinois.companies. |
| | | | |
Adam C. HeflinFadi M. Diya | 4851 |
| | Senior Vice President and Chief Nuclear Officer (Ameren Missouri) |
HeflinDiya joined Ameren Missouri in 2005 as2005. In 2008, Diya was elected vice president of nuclear operations andat Ameren Missouri. Effective January 16, 2014, Diya was elected senior vice president and chief nuclear officer of Ameren Missouri in 2008.Missouri. |
| | | | |
| Richard J. Mark | 5758 |
| | Chairman, President and Chief Executive Officer (Ameren Illinois) |
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.2002. He was elected senior vice president, customer operations of Ameren Missouri in 2005. In 2007, Mark relinquished his position at Ameren Services. Effective June 13, 2012, Mark relinquished his position at Ameren Missouri and was elected chairman, president and chief executive officer of Ameren Illinois. |
| | | | |
| Michael L. Moehn | 4344 |
| | Senior Vice President, Customer Operations (Ameren Missouri) |
Moehn joined Ameren Services in 2000 as assistant controller. In 2004, Moehn was elected vice president of corporate planning of Ameren Services.2000. In 2008, he was elected senior vice president, corporate planning and business risk management of Ameren Services. Effective January 1,In 2012, Moehn relinquished his position at Ameren Services and was elected senior vice president of customer operations of Ameren Illinois. Effective June 13,Subsequently in 2012, Moehn relinquished his position at Ameren Illinois and was elected senior vice president, customer operations of Ameren Missouri. |
| | | | |
| Charles D. Naslund | 6061 |
| | Executive Vice President (Ameren Services) (Effective March 1, 2013)Missouri) |
Naslund joined Ameren Missouri in 1974. He was elected vice president of power operations at Ameren Missouri in 1999, vice president of Ameren Services in 2000 and vice president of nuclear operations at Ameren Missouri in 2004. He relinquished his position at Ameren Services in 2001. Naslund was elected senior vice president and chief nuclear officer at Ameren Missouri in 2005. In 2008, he was elected chairman, president and chief executive officer of AER. Naslund relinquished his positions at Ameren Missouri in 2008. In 2011, Naslund assumed the position of senior vice president, generation and environmental projects of Ameren Missouri and relinquished his positions of chairman, president and chief executive officer of AER. On January 1,In 2013, Naslund relinquished his position at Ameren Missouri and was elected senior vice president of Ameren Services. On March 1,Subsequently in 2013, Naslund was elected executive vice president of Ameren Services. |
| | | |
Steven R. Sullivan | 52 |
| | Chairman, President and Chief Executive Officer (AER) |
After previous service as an Ameren Missouri staff attorney, Sullivan rejoined Ameren, Ameren Missouri, CIPSServices and Ameren Services in 1998 as vice president and general counsel and later in 1998 was elected secretary. In 2003, Sullivan was elected vice president, general counsel and secretary of CILCO. He was elected senior vice president, general counsel and secretary of Ameren, Ameren Missouri, CIPS, CILCO and Ameren Services in 2003 and of IP in 2004. Following the Ameren Illinois Merger in 2010, Sullivan remained senior vice president, general counsel and secretary at Ameren Illinois. In 2011, Sullivan was elected to the positions of chairman, president and chief executive officer of AER and relinquished his positions of senior vice president, general counsel and secretary of the Ameren companies.Missouri. |
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.executive officers or between the executive officers and any directors of the Ameren Companies. All of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
PART II
| |
| ITEM 5. | MARKET FOR REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASE OF EQUITY SECURITIES |
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren common shareholders of record totaled 60,81057,623 on January 31, 20132014. The following table presents the price ranges, closing prices, and dividends declared per Ameren common share for each quarter during 20122013 and 20112012.
| | | | High | | Low | | Close | | Dividends Declared | High | | Low | | Close | | Dividends Declared |
| 2013 Quarter Ended: | | | | | | | | |
| March 31 | | $ | 35.12 |
| | $ | 30.64 |
| | $ | 35.02 |
| | $ | 0.400 |
|
| June 30 | | 36.74 |
| | 32.34 |
| | 34.44 |
| | 0.400 |
|
| September 30 | | 36.70 |
| | 32.61 |
| | 34.84 |
| | 0.400 |
|
| December 31 | | 37.31 |
| | 34.18 |
| | 36.16 |
| | 0.400 |
|
| 2012 Quarter Ended: | | | | | | | | | | | | | | |
| March 31 | $ | 33.68 |
| | $ | 30.89 |
| | $ | 32.58 |
| | $ | 0.400 |
| $ | 33.68 |
| | $ | 30.89 |
| | $ | 32.58 |
| | $ | 0.400 |
|
| June 30 | 34.04 |
| | 31.15 |
| | 33.54 |
| | 0.400 |
| 34.04 |
| | 31.15 |
| | 33.54 |
| | 0.400 |
|
| September 30 | 35.30 |
| | 32.27 |
| | 32.67 |
| | 0.400 |
| 35.30 |
| | 32.27 |
| | 32.67 |
| | 0.400 |
|
| December 31 | 33.21 |
| | 28.43 |
| | 30.72 |
| | 0.400 |
| 33.21 |
| | 28.43 |
| | 30.72 |
| | 0.400 |
|
| 2011 Quarter Ended: | | | | | | | | |
| March 31 | $ | 29.14 |
| | $ | 26.46 |
| | $ | 28.07 |
| | $ | 0.385 |
| |
| June 30 | 30.14 |
| | 27.78 |
| | 28.84 |
| | 0.385 |
| |
| September 30 | 31.44 |
| | 25.55 |
| | 29.77 |
| | 0.385 |
| |
| December 31 | 34.11 |
| | 27.98 |
| | 33.13 |
| | 0.400 |
| |
There is no trading market for the common stock of Ameren Missouri and Ameren Illinois. Ameren holds all outstanding common stock of Ameren Missouri and Ameren Illinois.
The following table sets forth the quarterly common stock dividend payments made by Ameren and its registrant subsidiaries during 20122013 and 20112012:
| | | | 2012 | | 2011 | 2013 | | 2012 |
| (In millions) | Quarter Ended | | 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 |
| Ameren Missouri | $ | 100 |
| | $ | 100 |
| | $ | 100 |
| | $ | 100 |
| | $ | 184 |
| | $ | 84 |
| | $ | 67 |
| | $ | 68 |
| $ | 140 |
| | $ | 140 |
| | $ | 90 |
| | $ | 90 |
| | $ | 100 |
| | $ | 100 |
| | $ | 100 |
| | $ | 100 |
|
| Ameren Illinois | 57 |
| | 57 |
| | 38 |
| | 37 |
| | 89 |
| | 88 |
| | 88 |
| | 62 |
| 65 |
| | 15 |
| | 15 |
| | 15 |
| | 57 |
| | 57 |
| | 38 |
| | 37 |
|
| Ameren | 98 |
| | 97 |
| | 97 |
| | 90 |
| | 96 |
| | 93 |
| | 93 |
| | 93 |
| 97 |
| | 97 |
| | 97 |
| | 97 |
| | 98 |
| | 97 |
| | 97 |
| | 90 |
|
On February 8,14, 20132014, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 40 cents per share. The common share dividend is payable March 29,31, 20132014, to shareholders of record on March 13,12, 20132014.
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.
Purchases 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) Purchased(a) | | (b) Average Price Paid per Share (or Unit) | | (c) Total Number of Shares (or Units) Purchased As Part of Publicly Announced Plans or Programs | | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) That May Yet Be Purchased Under the Plans or Programs |
| October 1 – October 31, 2012 | — |
| | $ | — |
| | — |
| | — |
|
| November 1 – November 30, 2012 | 300 |
| | 29.32 |
| | — |
| | — |
|
| December 1 – December 31, 2012 | 3,213 |
| | 29.52 |
| | — |
| | — |
|
| Total | 3,513 |
| | $ | 29.50 |
| | — |
| | — |
|
| |
(a) | Comprised of shares of Ameren common stock purchased in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligation to distribute shares of common stock for vested performance units. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
Ameren Missouri, and Ameren Illinois did not purchase equity securities reportable under Item 703 of Regulation S-K during the period from October 1, 20122013, to December 31, 20122013.
Performance Graph
The following graph shows Ameren’s cumulative total shareholder return during the five years ended December 31, 20122013. 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, 20072008, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
28
| | | December 31, | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 |
| Ameren | $ | 100.00 |
| | $ | 65.41 |
| | $ | 58.40 |
| | $ | 62.41 |
| | $ | 77.23 |
| | $ | 75.28 |
| $ | 100.00 |
| | $ | 89.29 |
| | $ | 95.41 |
| | $ | 118.07 |
| | $ | 115.09 |
| | $ | 141.91 |
|
| S&P 500 Index | 100.00 |
| | 63.00 |
| | 79.67 |
| | 91.67 |
| | 93.60 |
| | 108.58 |
| 100.00 |
| | 126.46 |
| | 145.50 |
| | 148.58 |
| | 172.35 |
| | 228.17 |
|
| EEI Index | 100.00 |
| | 74.10 |
| | 82.04 |
| | 87.81 |
| | 105.36 |
| | 107.57 |
| 100.00 |
| | 110.71 |
| | 118.50 |
| | 142.19 |
| | 145.16 |
| | 164.05 |
|
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) | 2012 | | 2011 | | 2010 | | 2009 | | 2008 | 2013 | | 2012 | | 2011 | | 2010 | | 2009 |
Ameren(a): | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 6,828 |
| | $ | 7,531 |
| | $ | 7,638 |
| | $ | 7,135 |
| | $ | 7,869 |
| $ | 5,838 |
| | $ | 5,781 |
| | $ | 6,148 |
| | $ | 6,188 |
| | $ | 5,811 |
|
Operating income (loss)(b) | (1,240 | ) |
| 1,241 |
|
| 916 |
| | 1,416 |
| | 1,362 |
| |
Operating income(b) | | 1,184 |
| | 1,188 |
| | 1,033 |
| | 1,175 |
| | 890 |
|
| Income from continuing operations | | 518 |
| | 522 |
| | 437 |
| | 523 |
| | 369 |
|
Income (loss) from discontinued operations, net of taxes(c) | | (223 | ) | | (1,496 | ) | | 89 |
| | (372 | ) | | 255 |
|
| Net income (loss) attributable to Ameren Corporation | (974 | ) | | 519 |
| | 139 |
| | 612 |
| | 605 |
| 289 |
| | (974 | ) | | 519 |
| | 139 |
| | 612 |
|
| Common stock dividends | 382 |
| | 375 |
| | 368 |
| | 338 |
| | 534 |
| 388 |
| | 382 |
| | 375 |
| | 368 |
| | 338 |
|
| Earnings (loss) per share - basic and diluted | (4.01 | ) | | 2.15 |
| | 0.58 |
| | 2.78 |
| | 2.88 |
| |
| Continuing operations earnings per share – basic | | 2.11 |
| | 2.13 |
| | 1.79 |
| | 2.15 |
| | 1.63 |
|
| Continuing operations earnings per share – diluted | | 2.10 |
| | 2.13 |
| | 1.79 |
| | 2.15 |
| | 1.63 |
|
| Common stock dividends per share | 1.60 |
| | 1.555 |
| | 1.54 |
| | 1.54 |
| | 2.54 |
| 1.60 |
| | 1.60 |
| | 1.555 |
| | 1.54 |
| | 1.54 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 21,835 |
| | $ | 23,645 |
| | $ | 23,511 |
| | $ | 23,702 |
| | $ | 22,671 |
| |
Total assets(d) | | $ | 21,042 |
| | $ | 22,230 |
| | $ | 23,723 |
| | $ | 23,511 |
| | $ | 23,701 |
|
| Long-term debt, excluding current maturities | 6,626 |
| | 6,677 |
| | 6,853 |
| | 7,111 |
| | 6,554 |
| 5,504 |
| | 5,802 |
| | 5,853 |
| | 6,029 |
| | 6,287 |
|
| Total Ameren Corporation stockholders’ equity | 6,616 |
| | 7,919 |
| | 7,730 |
| | 7,856 |
| | 6,963 |
| 6,544 |
| | 6,616 |
| | 7,919 |
| | 7,730 |
| | 7,856 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 3,272 |
| | $ | 3,383 |
| | $ | 3,197 |
| | $ | 2,874 |
| | $ | 2,960 |
| $ | 3,541 |
| | $ | 3,272 |
| | $ | 3,383 |
| | $ | 3,197 |
| | $ | 2,874 |
|
Operating income(c) | 845 |
| | 609 |
| | 711 |
| | 566 |
| | 514 |
| |
Operating income(b) | | 803 |
| | 845 |
| | 609 |
| | 711 |
| | 566 |
|
| Net income available to common stockholder | 416 |
| | 287 |
| | 364 |
| | 259 |
| | 245 |
| 395 |
| | 416 |
| | 287 |
| | 364 |
| | 259 |
|
| Dividends to parent | 400 |
| | 403 |
| | 235 |
| | 175 |
| | 264 |
| 460 |
| | 400 |
| | 403 |
| | 235 |
| | 175 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
| Total assets | $ | 13,043 |
| | $ | 12,757 |
| | $ | 12,504 |
| | $ | 12,219 |
| | $ | 11,529 |
| $ | 12,904 |
| | $ | 13,043 |
| | $ | 12,757 |
| | $ | 12,504 |
| | $ | 12,219 |
|
| Long-term debt, excluding current maturities | 3,801 |
| | 3,772 |
| | 3,949 |
| | 4,018 |
| | 3,673 |
| 3,648 |
| | 3,801 |
| | 3,772 |
| | 3,949 |
| | 4,018 |
|
| Total stockholders’ equity | 4,054 |
| | 4,037 |
| | 4,153 |
| | 4,057 |
| | 3,562 |
| 3,993 |
| | 4,054 |
| | 4,037 |
| | 4,153 |
| | 4,057 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
| Operating revenues | $ | 2,525 |
| | $ | 2,787 |
| | $ | 3,014 |
| | $ | 2,984 |
| | $ | 3,508 |
| $ | 2,311 |
| | $ | 2,525 |
| | $ | 2,787 |
| | $ | 3,014 |
| | $ | 2,984 |
|
| Operating income | 377 |
| | 458 |
| | 498 |
| | 363 |
| | 191 |
| 415 |
| | 377 |
| | 458 |
| | 498 |
| | 363 |
|
| Income from continuing operations | 144 |
| | 196 |
| | 212 |
| | 133 |
| | 41 |
| |
| Net income available to common stockholder | 141 |
| | 193 |
| | 248 |
| | 241 |
| | 87 |
| 160 |
| | 141 |
| | 193 |
| | 248 |
| | 241 |
|
| Dividends to parent | 189 |
| | 327 |
| | 133 |
| | 98 |
| | 60 |
| 110 |
| | 189 |
| | 327 |
| | 133 |
| | 98 |
|
| As of December 31: | | | | | | | | | | | | | | | | | | |
Total assets(d) | $ | 7,282 |
| | $ | 7,213 |
| | $ | 7,406 |
| | $ | 8,298 |
| | $ | 8,023 |
| |
Total assets(e) | | $ | 7,454 |
| | $ | 7,282 |
| | $ | 7,213 |
| | $ | 7,406 |
| | $ | 8,298 |
|
| Long-term debt, excluding current maturities | 1,577 |
| | 1,657 |
| | 1,657 |
| | 1,847 |
| | 1,850 |
| 1,856 |
| | 1,577 |
| | 1,657 |
| | 1,657 |
| | 1,847 |
|
| Total stockholders’ equity | 2,401 |
| | 2,452 |
| | 2,576 |
| | 3,072 |
| | 2,655 |
| 2,448 |
| | 2,401 |
| | 2,452 |
| | 2,576 |
| | 3,072 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | Includes “Impairment and other charges”“Taum Sauk regulatory disallowance” of $2,578 million, $125 million and $58989 million recorded at Ameren duringand Ameren Missouri for the yearsyear ended December 31, 2012, 2011, and 2010, respectively.2011. |
| |
| (c) | Includes “Loss from regulatory disallowance”See Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of $89 million recorded during the year ended December 31, 2011.
this report for additional information. |
| |
| (d) | Includes total assets from discontinued operations of $1,117$165 million, $1,611 million, $3,721 million, $3,825 million, and $1,081$4,593 million at December 31, 2013, 2012, 2011, 2010, and 2009, and 2008, respectively. |
| |
| (e) | Includes total assets from discontinued operations (AERG) of $1,117 million at December 31, 2009. |
| |
| ITEM 7. | MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
OVERVIEW
Ameren Executive Summary
Operations
In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business segment's long-lived assets. This determination resulted from Ameren's analysis of the current and projected future financial condition of its Merchant Generation business, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this business was no longer a core component of its future business strategy. The volatility of earnings and cash flows of the Merchant Generation business, as well as the high degree of uncertainty regarding future returns on incremental capital invested in this business, are not in alignment with Ameren's current strategy. Ameren's decision to exit the business follows a trend of decreasing earnings and cash flows from the Merchant Generation business since 2008. Ameren's date and method of exit from the Merchant Generation business is currently uncertain with a sale or restructuring possible. Senior management and Ameren's board of directors are focused on maximizing the overall benefit to Ameren consistent with its legal obligations.
While working to exit the Merchant Generation business, Ameren remains focused on its rate-regulated utilities, including growing investments in jurisdictions with constructive regulatory frameworks. Ameren continues to seek modern, constructive regulatory frameworks, which provide timely cash flows and a reasonable opportunity to earn fair returns on investments that are in the best long-term interest of Ameren's customers. These frameworks support Ameren's rate-regulated businesses' ability to obtain cash on a timelier basis, to reinvest in energy infrastructure and also attract capital on terms that facilitate timely investments to modernize their aging infrastructure.
In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million. These new rates became effective on January 2, 2013. The MoPSC's December 2012 electric rate order improved Ameren Missouri's regulatory framework for energy efficiency programs as well as authorized the implementation of a new storm restoration cost tracking mechanism.
In 2012, Ameren Illinois elected to participate in the IEIMA's performance-based formula ratemaking framework. The IEIMA was designed to promote investment in electric grid modernization and create jobs through the establishment of formula ratemaking for electric delivery service. Ameren Illinois believes the ICC has incorrectly implemented the IEIMA in both of its 2012 electric delivery service rate orders. As a result, Ameren Illinois has appealed both 2012 electric delivery service rate orders to the Appellate Court of the Fourth District of Illinois and is also seeking a legislative solution to address the ICC's
implementation of the IEIMA. Additionally, in January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by $50 million. This request was based on a 2014 future test year.
Ameren continues to proceed with its plans to increase its investment in FERC-regulated electric transmission. In 2013, for both Ameren Illinois and ATXI, transmission rates will be updated annually based on a forward-looking calculation with a revenue requirement reconciliation. Ameren expects to invest a total of approximately $2.2 billion in FERC-regulated transmission projects over the next five years. The Ameren Illinois portion of that total, approximately $1 billion, is for projects focused on local load growth and reliability needs. ATXI, through its construction of three MISO-approved regional multi-value electric transmission projects, expects to invest approximately $1.2 billion over the next five years. In November 2012, ATXI filed a request with the ICC for a certificate of public convenience and necessity for the Illinois Rivers project. Once ATXI receives the certificate of public convenience and necessity, it can begin to acquire right of way for the Illinois Rivers project. A full range of construction activities for the Illinois Rivers project is expected to begin in 2014.
Earnings
Ameren reported a net loss of $974 million, or $4.01 per share, for 2012 compared with net income of $519 million, or $2.15 per share, in 2011. The main factor contributing to the net loss in 2012, compared with net income in 2011, was the 2012 impairments of Merchant Generation's long-lived assets resulting from Ameren's determination in December 2012 that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously useful lives of that business segment's long-lived assets, coupled with the sharp decline in the market price for power in the first quarter of 2012. The decline in Merchant Generation earnings also reflected lower power prices and higher fuel costs. Ameren's earnings also decreased in 2012, compared with 2011, because of a decline in Ameren Illinois' earnings primarily due to the impacts of implementing the IEIMA's formula ratemaking in 2012, including a lower allowed return on equity and required nonrecoverable contributions, as well as lower natural gas sales volumes as a result of warmer 2012 winter temperatures. Summer weather was much warmer than normal in 2012, but similar to 2011. The earnings declines in the Merchant Generation and Ameren Illinois segments were partially offset by increased Ameren Missouri earnings due primarily to the full year effect of the 2011 electric rate increase as well as lower operations and maintenance expense reflecting the absence of a refueling outage at the Callaway energy center in 2012, decreased labor costs primarily due to staff reductions resulting from the 2011 voluntary separation plan, and reduced major storm-related costs. Ameren Missouri's 2012 earnings, compared to 2011 earnings, also benefited from a favorable 2012 FERC order related to a disputed power purchase agreement that expired in 2009 and the absence of a 2011 charge to earnings related to the FAC. These positive Ameren Missouri factors were partially offset by higher
depreciation expense and lower electric sales volumes due to warmer 2012 winter temperatures.
Liquidity
Cash flows from operations of $1.7 billion were used to pay dividends to common stockholders of $382 million and to fund capital expenditures of $1.2 billion. At December 31, 2012, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under existing credit agreements, of approximately $2.3 billion, which was a $100 million increase from the amount of available liquidity at December 31, 2011.
Capital Spending
From 2013 through 2017, Ameren's cumulative capital spending is projected to range between $7.4 billion and $9.5 billion. Much of this spending is at Ameren's rate-regulated utilities, including a total of approximately $1.2 billion at ATXI to invest in its electric transmission assets as discussed above. The Merchant Generation segment's capital spending is expected to be up to $385 million from 2013 through 2017, assuming Ameren continues to own the Merchant Generation energy centers for the entire period.
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are its equity interests in 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. 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
Below is a summary description of Ameren Missouri and Ameren Illinois. A more detailed description can be found in Note 1 -– Summary of Significant Accounting Policies under Part II, Item 8, of this report for a detailed description of our principal subsidiaries.report.
Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.
Ameren Illinois operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business and is developing the Illinois Rivers project. The Illinois Rivers project is a MISO-approved project to build a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri at an estimated cost of $1.1 billion.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER consiststo IPH. On December 2, 2013, Ameren completed the divestiture of non-rate-regulated operations, including Genco, AERG, Marketing Company, and through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.
In December 2012, Ameren determined that it intendsNew AER to and it is probable that it will, exitIPH. On January 31, 2014, Medina Valley completed its Merchant Generation business before the endsale of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren’s analysis of the currentElgin, Gibson City, and projected future
financial condition of its Merchant Generation business segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this business segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation business segment’s, including Genco's, reliance on Ameren’s financial support and shared services support. Furthermore, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying values of the Merchant GenerationGrand Tower gas-fired energy centers except for the Joppa coal-fired energy center, to their estimated fair values.Rockland Capital. See Note 17 - Impairment16 – Divestiture Transactions and Other ChargesDiscontinued Operations under Part II, Item 8, of this report for additional information. Ameren's dateThese divestitures position Ameren to focus exclusively on its rate-regulated electric, natural gas, and method of exit from the Merchant Generation business is currently uncertain. Exit strategies may include the sale of all or partstransmission operations.
As a result of the Merchant Generation businesstransaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the restructuring of all or a portion of Ameren's equity position in Genco. Ameren's Merchant Generation long-lived assets have not been classified as held-for-sale under authoritative accounting guidance as all criteria to qualifygas-fired energy centers qualified for thatdiscontinued operations presentation were not metbeginning March 14, 2013. In addition, as of December 31, 2012. Specifically,2, 2013, Ameren did not consider it probable that a disposition would occur within one year.
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERGabandoned the Meredosia and AER completed a two-step corporate internal reorganization. The first stepHutsonville energy centers upon the completion of the reorganizationdivestiture of New AER to IPH. Ameren is prohibited from operating these energy centers through December 31, 2020, as a provision of the Illinois Pollution Control Board's November 2013 order granting IPH a variance of the MPS. As a result, Ameren determined that the Meredosia and Hutsonville energy centers qualified for discontinued operations presentation as of December 2, 2013. The Meredosia and Hutsonville energy centers ceased operations at December 31, 2011, and therefore 2011 was the last year those energy centers had a material effect on Ameren's
consolidated financial statements. As a result of these events, Ameren Illinois Merger. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Amerenhas segregated New AER’s and the subsequent contribution by Ameren of the AERG stock to AER. Ameren Illinois segregated AERG’sElgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers’ operating results, assets, and cash flowsliabilities and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. Unless otherwise stated, the following sections of Management's Discussion and Analysis of Financial Condition and Results of Operations exclude discontinued operations for all periods presented. See Note 16 - 2010 Corporate Reorganization– Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for additional information.information regarding that presentation.
The financial statements of Ameren and Ameren Illinois are prepared on a consolidated basis and therefore include the accounts of their respectiveits majority-owned subsidiaries. Ameren Illinois' financial statements are consolidated becauseMissouri and Ameren Illinois included AERG in its statements of income and cash flows during 2010. Ameren Missouri hashave no subsidiaries, and therefore itstheir financial statements are not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are 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 that 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.
OVERVIEW
With its exit from the merchant generation business complete, Ameren is focused exclusively on its rate-regulated utilities. Ameren plans to invest in and operate its utilities in a manner consistent with existing regulatory frameworks, optimizing operating and capital spending within these frameworks, including managing costs in a disciplined manner. As a result, Ameren intends to allocate significant and increasing amounts of discretionary capital to FERC-regulated electric transmission service and Illinois electric delivery service projects because these services operate under formulaic and constructive regulatory frameworks.
Ameren Missouri expects to file an electric service rate case in July 2014. The rate case is expected to include the costs associated with the completion of two significant capital projects, which projects are the replacement of the nuclear reactor head at Ameren Missouri's Callaway energy center and upgrades to precipitators at Ameren Missouri's coal-fired Labadie energy center. Both of these projects are scheduled for completion during the fourth quarter of 2014. The timing of the rate case filing is designed to minimize, to the extent possible under the existing regulatory framework, the regulatory lag on these two important capital investments.
Ameren Missouri continues to seek a regulatory framework with reduced regulatory lag, which provides timely cash flows and a reasonable opportunity to earn fair returns on investments that are in the best long-term interest of its customers. An enhanced
regulatory framework would increase Ameren Missouri's ability to reinvest discretionary capital in aging energy infrastructure.
Ameren Illinois continues to participate in the IEIMA’s performance-based formula ratemaking framework for electric delivery service. Under this framework, the ICC issued an order in December 2013 which approved a net $45 million reduction in Ameren Illinois' electric delivery service rates used for 2014 customer billings, compared with 2013. The reduction was primarily caused by a $68 million refund due to customers in 2014 as a result of the 2012 revenue requirement reconciliation, partially offset by a $23 million increase in recoverable costs. These rates will affect Ameren Illinois’ cash flows during 2014, but not its operating revenues, which will instead be determined by the IEIMA’s 2014 revenue requirement reconciliation. In 2013, Illinois enacted into law certain amendments to the IEIMA that modified its implementation, which were consistent with Ameren Illinois’ view of the IEIMA’s performance-based formula rate framework.
In December 2013, the ICC issued a rate order that approved an increase in revenues for natural gas delivery service of $32 million, based on a 2014 future test year, with rates that became effective January 1, 2014. Also in 2013, Illinois enacted legislation that encourages Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provides for additional ICC oversight of natural gas utility performance. The law provides for a rate rider mechanism to recover costs of certain natural gas infrastructure investments made between rate cases. Ameren Illinois expects to begin including investments under this regulatory framework in 2015.
Over the next five years, Ameren plans to invest $2.25 billion in FERC-regulated electric transmission projects (ATXI - $1.4 billion; Ameren Illinois - $850 million). In 2013, ATXI obtained a certificate of public convenience and necessity from the ICC approving portions of its Illinois Rivers transmission project. In February 2014, the ICC issued a final order on rehearing approving the remaining substations and routes of the project. The Illinois Rivers project has an estimated total project cost of $1.1 billion. A full range of construction activities for the Illinois Rivers project is scheduled in 2014. The Ameren Illinois transmission investments are local reliability projects.
Earnings
Ameren reported net income of $289 million, or $1.18 per diluted share, for 2013, compared with net loss of $974 million, or a loss of $4.01 per diluted share, in 2012. Net income attributable to Ameren Corporation from continuing operations was $512 million, or $2.10 per diluted share, for 2013, and $516 million, or $2.13 per diluted share, for 2012. Ameren's earnings from continuing operations decreased in 2013, compared with 2012, in part, because of reduced earnings at Ameren Missouri due to the costs of the Callaway energy center's 2013 scheduled refueling and maintenance outage, compared with 2012 when there was no refueling outage, a reduction in revenues resulting from a MoPSC order related to the FAC, and the absence in 2013 of a 2012 benefit from a FERC-ordered refund from Entergy.
Additionally, earnings from continuing operations were unfavorably affected by decreased electric demand resulting from 2013 summer temperatures that were cooler than warmer-than-normal 2012 temperatures partially offset by increased electric and natural gas demand resulting from winter temperatures in 2013 that were colder than winter temperatures in 2012. Earnings from continuing operations were also unfavorably affected by the ICC's December 2013 order that resulted in a charge to earnings for the ICC's disallowance of a portion of debt premium costs. Net income from continuing operations at Ameren was favorably affected in 2013, compared with 2012, by rate increases for Ameren Missouri electric and Ameren Illinois transmission services, both effective in January 2013, as well as higher Ameren Illinois electric delivery service earnings. The latter reflected the absence, in 2013, of a 2012 required IEIMA contribution to the Illinois Science and Energy Innovation Trust, as well as increased rate base and a higher allowed return on equity due to higher 30-year United States Treasury bond yields under formula ratemaking. During 2013, Ameren Missouri and Ameren Illinois continued to align spending with regulatory outcomes, policies, and economic conditions.
Liquidity
Cash flows from operations associated with continuing operations of $1.6 billion and available cash on hand were used to pay dividends to common stockholders of $388 million and to fund capital expenditures of $1.4 billion. At December 31, 2013, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under existing credit agreements, of approximately $1.7 billion.
Capital Spending
In 2013, Ameren made significant investments in its utilities and expects that trend to continue into the foreseeable future. From 2014 through 2018, Ameren's cumulative capital spending is projected to range between $8 billion and nearly $9 billion. The spending includes approximately $1.4 billion for ATXI's investment in its electric transmission assets.
RESULTS OF OPERATIONS
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 prices we charge for our services. Merchant Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, methane gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly because of 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 natural gas delivery service businesses, a purchased power cost recovery mechanism for our Illinois electric delivery service business, and a FAC for our Missouri electric utility business. Ameren Illinois' electric delivery service utility business, pursuant to the IEIMA,
conducts an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year, with recoveries from or refunds to customers made in a subsequent year. Included in Ameren Illinois' revenue requirement reconciliation is a formula for the return on equity, which is equal to the average of the monthly yields of 30-year United States treasury bonds plus 590 basis points for 2012 and 580 basis points thereafter.points. Therefore, Ameren Illinois' annual return on equity will be directly correlated to yields on United States treasury bonds. Fluctuations in interest rates and conditions in the capital and credit markets also 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 energy centers and transmission and distribution systems and the level of purchased power costs, operations and maintenance costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.
Earnings Summary
The following table presents a summary of Ameren's earnings for the years ended December 31, 2013, 2012, and 2011:
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
| Net income (loss) attributable to Ameren Corporation | $ | 289 |
| | $ | (974 | ) | | $ | 519 |
|
| Earnings (loss) per common share - diluted | 1.18 |
| | (4.01 | ) | | 2.15 |
|
| | | | | | |
| Net income attributable to Ameren Corporation - continuing operations | 512 |
| | 516 |
| | 431 |
|
| Earnings per common share - diluted - continuing operations | 2.10 |
| | 2.13 |
| | 1.79 |
|
2013 versus 2012
Net lossincome attributable to Ameren Corporation was $974from continuing operations in 2013 decreased $4 million,, or $4.01$0.03 per diluted share, forfrom 2012. Net income attributable to Ameren Corporation was $519 million, or $2.15 per share, for 2011, and $139 million, or $0.58 per share, for 2010.
2012 versus 2011
The net loss attributable to Ameren Corporation in 2012 was primarily caused by a net loss in the Merchant Generation segment of $1.516 billion in 2012. The Merchant Generation segment reported net income of $45 million in 2011. Net income attributable to Ameren Corporation in 2012 decreased in the Ameren Illinois Segment by $52 million from 2011 and increased in the Ameren Missouri segment by $129$21 million, from 2011. partially offset by an increase in the Ameren Illinois segment of $19 million.
Compared with 20112012 earnings per share 2012from continuing operations, 2013 earnings per share from continuing operations were unfavorably affected by:
the 2012 impairments of Merchant Generation's long-lived assets resulting from Ameren's determination in December
2012 that it intends to, and it is probable that it will, exit its Merchant Generation segment before the endcost of the previously estimated useful lives of that business segment's long-lived assets, coupled with the sharp declineCallaway energy center's scheduled refueling and maintenance outage in the market price of power2013. There was no Callaway refueling and maintenance outage in the first quarter of 2012 ($6.42 per share);
lower electric margins in the Merchant Generation segment, largely due to reduced generation volumes caused by lower market prices for power as well as higher fuel and related transportation costs (34(10 cents per share);
a reduction in Ameren Illinois' electricMissouri revenues resulting from a July 2013 MoPSC order that required a refund to customers for the earnings primarily caused by a lower allowed return on equity under electric delivery service formula ratemaking and required donations pursuantassociated with certain long-term partial requirements sales recognized from October 1, 2009, to the IEIMA (17May 31, 2011 (7 cents per share);
reducedthe absence in 2013 of a reduction in Ameren Missouri's purchased power expense and an increase in interest
income, each as a result of a FERC-ordered refund received in 2012 from Entergy for a power purchase agreement that expired in 2009 (7 cents per share);
decreased electric demand resulting from summer temperatures in 2013 that were cooler than the warmer-than-normal temperatures in 2012, partially offset by increased electric and natural gas demand as a result of warmer 2012resulting from winter temperatures (estimated at 7in 2013 that were colder than winter temperatures in 2012 (6 cents per share);
the ICC's December 2013 orders disallowing recovery from customers of a portion of the premium paid by Ameren Illinois for a tender offer in August 2012 to repurchase outstanding senior secured notes (4 cents per share); and
reduced rate-regulated retail sales volumes, excluding the effects of abnormal weather, as sales volumes declinedincreased depreciation primarily due to continued economic pressure, energy efficiency measures,infrastructure additions at Ameren Missouri and customer conservation efforts, among other items (2Ameren Illinois and Ameren Illinois' new electric depreciation rates (3 cents per share).
Compared with 2012 earnings per share from continuing operations, 2013 earnings per share from continuing operations were favorably affected by:
higher Ameren Missouri utility rates pursuant to an order issued by the MoPSC, which became effective in January 2013, partially offset by increased regulatory asset amortization as directed by the rate order. This excludes MEEIA impacts, which are discussed separately below (12 cents per share);
higher revenues associated with Ameren Missouri's MEEIA program cost and projected lost revenue recovery mechanism (9 cents per share), which were partially offset by lower revenues resulting from reduced demand due to energy efficiency programs;
higher electric transmission rates at Ameren Illinois and ATXI (8 cents per share); and
an increase in Ameren Illinois' electric delivery service earnings under formula ratemaking, favorably affected primarily by an increased rate base, a higher allowed return on equity, and lower required contributions pursuant to the IEIMA (8 cents per share).
The cents per share information presented above is based on diluted average shares outstanding in 2012.
2012 versus 2011
Net income attributable to Ameren Corporation from continuing operations in 2012 increased $85 million, or $0.34 per diluted share, from 2011. Net income attributable to Ameren Corporation increased in the Ameren Missouri segment by $129 million, which was partially offset by a decrease in the Ameren Illinois segment of $52 million.
Compared with 2011 earnings per share from continuing operations, 2012 earnings per share from continuing operations were favorably affected by:
the absence in 2012 of charges recorded ina 2011 at Ameren Missouricharge for the MoPSC's July 2011 disallowance of costs of enhancements relating to the rebuilding of Ameren Missouri's Taum Sauk energy center in
excess of amounts recovered from property insurance and at Merchant Generation for the closure of the Meredosia and Hutsonville energy centers (32(23 cents per share);
higher utility rates at Ameren Missouri and Ameren Illinois. Ameren Missouri's electric rates increased pursuant to an order issued by the MoPSC, which became effective in July 2011. The favorable impact of the Ameren Missouri rate increase on earnings was reduced by the increased regulatory asset amortization directed by the rate order. Ameren Illinois' natural gas rates increased pursuant to an order issued by the ICC, which became effective in mid-January 2012 (22 cents per share);
the absence in 2012 of a Callaway energy center refueling and maintenance outage (11 cents per share);
reduction in operations and maintenance expenses at both Ameren Missouri and Merchant Generation energy centers due to fewer outages and a reduction in employees (10 cents per share);
the impact of fewer major storms on operations and maintenance expenses (9 cents per share);
a reduction in Ameren Missouri's purchased power expense and an increase in interest income, each as a result of a FERC-ordered refund received in 2012 from Entergy for a power purchase agreement that expired in 2009 (7 cents per share);
the absence in 2012 of a 2011 charge associated with voluntary separation offers to eligible Ameren Missouri and Ameren Services employees (7 cents per share);
the absence in 2012 of a reduction in Ameren Missouri's
revenues as a result of the MoPSC's April 2011 FAC prudence review order covering the period from March 1, 2009, to September 30, 2009, which resulted incaused Ameren Missouri recordingto record an obligation to refund to its electric customers the earnings associated with certain previously recognized sales (5 cents per share); and
a decreasereduction in Merchant Generation depreciation and amortization expense due tolabor costs because of staff reductions at Ameren Missouri, primarily resulting from the asset impairments recorded in 2012, a change in 2011 in the estimates relating to asset retirement obligations, and the closure of the Meredosia and Hutsonville energy centersvoluntary separation plan. The favorable effect at the end of 2011, which Ameren Missouri
was partially offset by increased labor costs at Ameren Illinois due to staff additions to comply with the requirements of the IEIMA (2 cents per share).
Compared with 2011 earnings from continuing operations, 2012 earnings from continuing operations were unfavorably affected by:
a reduction in Ameren Illinois' electric earnings primarily caused by a lower allowed return on equity under electric delivery service formula ratemaking and required donations pursuant to the IEIMA (17 cents per share);
an increase in Ameren Missouri depreciation and amortization expense caused primarily by the installation of scrubbers at the Sioux energy center (4 cents per share).
The cents per share information presented above is based on average shares outstanding in 2011.
2011 versus 2010
Net income attributable to Ameren Corporation increased $380 million, and earnings per share increased $1.57 in 2011 compared with 2010. The Merchant Generation segment reported net income attributable to Ameren Corporation of $45 million in 2011, compared with a $409 million net loss in 2010. Net income attributable to Ameren Corporation decreased in the Ameren Missouri segment and Ameren Illinois Segment by $77 million and $15 million, respectively, in 2011 compared with 2010.
Compared with 2010 earnings per share, 2011 earnings were favorably affected by:
reduced impairment and other charges in the Merchant Generation segment, offset in part by a charge to earnings related to the MoPSC’s July 2011 disallowance of costs of enhancements relating to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance ($1.87 per share);
higher Ameren Missouri electric rates pursuant to orders issued by the MoPSC, which became effective in June 2010 and in July 2011, as well as higher Ameren Missouri natural gas rates pursuant to a MoPSC order, which became effective in late February 2011. The impact of the Ameren Missouri electric rate increases on earnings was reduced by the adoption of life span depreciation methodology, recognition in 2010 of regulatory assets for previously expensed costs in the prior-year period, and increased regulatory asset amortization as directed by the rate orders (17 cents per share). These amounts exclude the unfavorable impact of the charge to earnings related to the MoPSC’s disallowance of Taum Sauk rebuilding costs discussed above;
lower interest expense, primarily due to the maturity and repayment of $200 million of Merchant Generation’s senior secured notes in November 2010, the redemption of $66 million of Ameren Missouri’s subordinated deferrable interest debentures in September 2010, Ameren Illinois’ redemptions of $150 million of senior secured notes and $40 million of
first mortgage bonds in June 2011 and September 2010, respectively, and a reduction in borrowings under credit facility agreements (12(8 cents per share);
higher Ameren Illinoisreduced electric rates pursuant to orders issued by the ICC in 2010 (6 cents per share);
the absence in 2011and natural gas demand as a result of a charge for the impact on deferred taxes from changes in federal health care laws (6 cents per share);
the absence in 2011 of charges recorded in 2010 for cancelled or unrecoverable projectswarmer 2012 winter temperatures (estimated at Ameren Missouri (6 cents per share);
a reduction in operations and maintenance expense related to plant maintenance, primarily at Ameren Missouri, as fewer costs were incurred for major outages at coal-fired energy centers because the scope of the outages in 2011 was not as extensive as the scope of the outages conducted in 2010 (57 cents per share); and
reduction in expense as a result of disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.
Compared with 2010 earnings per share, 2011 earnings were unfavorably affected by:
lower electric margins in the Merchant Generation segment, largely due to lower realized revenue per megawatthour sold and higher fuel and related transportation costs (21 cents per share). This amount excludes the unfavorable impacts of net unrealized MTM activity discussed below;
reduced rate-regulated retail sales volumes, excluding the effects of abnormal weather, as sales volumes declined due to continued economic pressure, energy efficiency measures, and customer conservation efforts, as well as lower wholesale sales at Ameren Missouri due to a reduction in customers and the expiration of favorably priced contracts, among other items (15 cents per share);
unrealized net losses on MTM activity primarily related to nonqualifying power hedges and fuel-related contracts as well as unfavorable changes in the market value of investments used to support Ameren’s deferred compensation plans (10 cents per share);
the impact of weather conditions on electric and natural gas demand (estimated at 10 cents per share);
increased operations and maintenance expenses as a result of major storms in 2011 (9 cents per share);
a reduction in allowance for equity funds used during construction reflecting the 2010 completion of two scrubbers at Ameren Missouri’s Sioux energy center (8 cents per share);
increased operations and maintenance expenses associated with voluntary separation offers to eligible Ameren Missouri and Ameren Services employees during 2011 (7 cents per share);
a reduction in revenues resulting from the MoPSC’s April 2011 order with respect to its FAC review for the period from March 1, 2009, to September 30, 2009, as discussed above. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information (5 cents per share); and
an increase in depreciation and amortization expense caused primarily by the installation of scrubbers at Ameren Missouri’s Sioux energy center as well as other capital additions (4(2 cents per share).
The cents per share information presented above is based on diluted average shares outstanding in 2010.2011.
For additional details regarding the Ameren Companies’ results of operations, including explanations of Margins, Other Operations and Maintenance Expenses, Impairment and Other Charges,Taum Sauk Regulatory Disallowance, Depreciation and Amortization, Taxes Other Than Income Taxes, Other Income and Expenses, Interest Charges, Income Taxes and Income (Loss) from Discontinued Operations, Net of Taxes, see the major headings below.
Below is a table of income statement components by segment for the years ended December 31, 2013, 2012, 2011, and 2010:
| | | 2013 | | Ameren Missouri | | Ameren Illinois | | Other / Intersegment Eliminations | | Total |
| Electric margins | | $ | 2,407 |
| | $ | 1,081 |
| | $ | (3 | ) | | $ | 3,485 |
|
| Natural gas margins | | 83 |
| | 399 |
| | (2 | ) | | 480 |
|
| Other revenues | | 1 |
| | 3 |
| | (4 | ) | | — |
|
| Other operations and maintenance | | (915 | ) | | (693 | ) | | (9 | ) | | (1,617 | ) |
| Depreciation and amortization | | (454 | ) | | (243 | ) | | (9 | ) | | (706 | ) |
| Taxes other than income taxes | | (319 | ) | | (132 | ) | | (7 | ) | | (458 | ) |
| Other income and (expenses) | | 47 |
| | 1 |
| | (5 | ) | | 43 |
|
| Interest charges | | (210 | ) | | (143 | ) | | (45 | ) | | (398 | ) |
| Income (taxes) benefit | | (242 | ) | | (110 | ) | | 41 |
| | (311 | ) |
| Income (loss) from continuing operations | | 398 |
| | 163 |
| | (43 | ) | | 518 |
|
| Loss from discontinued operations, net of taxes | | — |
| | — |
| | (223 | ) | | (223 | ) |
| Net income (loss) | | 398 |
| | 163 |
| | (266 | ) | | 295 |
|
| Net income attributable to noncontrolling interests – continuing operations | | (3 | ) | | (3 | ) | | — |
| | (6 | ) |
| Net income (loss) attributable to Ameren Corporation | | $ | 395 |
| | $ | 160 |
| | $ | (266 | ) | | $ | 289 |
|
| 2012 | Ameren Missouri | | Ameren Illinois Segment | | Merchant Generation | | Other / Intersegment Eliminations | | Total | | | | | | | |
| Electric margins | $ | 2,340 |
| | $ | 1,034 |
| | $ | 518 |
| | $ | (11 | ) | | $ | 3,881 |
| $ | 2,340 |
| | $ | 1,034 |
| | $ | (11 | ) | | $ | 3,363 |
|
| Natural gas margins | 75 |
| | 378 |
| | — |
| | (1 | ) | | 452 |
| 75 |
| | 378 |
| | (1 | ) | | 452 |
|
| Other revenues | 1 |
| | — |
| | — |
| | (1 | ) | | — |
| 1 |
| | — |
| | (1 | ) | | — |
|
| Other operations and maintenance | (827 | ) | | (684 | ) | | (259 | ) | | 18 |
| | (1,752 | ) | (827 | ) | | (684 | ) | | — |
| | (1,511 | ) |
| Impairment and other charges | — |
| | — |
| | (2,578 | ) | | — |
| | (2,578 | ) | |
| Depreciation and amortization | (440 | ) | | (221 | ) | | (102 | ) | | (12 | ) | | (775 | ) | (440 | ) | | (221 | ) | | (12 | ) | | (673 | ) |
| Taxes other than income taxes | (304 | ) | | (130 | ) | | (25 | ) | | (9 | ) | | (468 | ) | (304 | ) | | (130 | ) | | (9 | ) | | (443 | ) |
| Other income and (expenses) | 49 |
| | (10 | ) | | (1 | ) | | (4 | ) | | 34 |
| 49 |
| | (10 | ) | | (6 | ) | | 33 |
|
| Interest charges | (223 | ) | | (129 | ) | | (95 | ) | | (1 | ) | | (448 | ) | (223 | ) | | (129 | ) | | (40 | ) | | (392 | ) |
| Income (taxes) benefit | (252 | ) | | (94 | ) | | 1,019 |
| | 7 |
| | 680 |
| (252 | ) | | (94 | ) | | 39 |
| | (307 | ) |
| Income (loss) from continuing operations | | 419 |
| | 144 |
| | (41 | ) | | 522 |
|
| Loss from discontinued operations, net of taxes | | — |
| | — |
| | (1,496 | ) | | (1,496 | ) |
| Net income (loss) | 419 |
| | 144 |
| | (1,523 | ) | | (14 | ) | | (974 | ) | 419 |
| | 144 |
| | (1,537 | ) | | (974 | ) |
| Noncontrolling interest and preferred dividends | (3 | ) | | (3 | ) | | 7 |
| | (1 | ) | | — |
| |
| Net income attributable to noncontrolling interests – continuing operations | | (3 | ) | | (3 | ) | | — |
| | (6 | ) |
| Net loss attributable to noncontrolling interests – discontinued operations | | — |
| | — |
| | 6 |
| | 6 |
|
| Net income (loss) attributable to Ameren Corporation | $ | 416 |
| | $ | 141 |
| | $ | (1,516 | ) | | $ | (15 | ) | | $ | (974 | ) | $ | 416 |
| | $ | 141 |
| | $ | (1,531 | ) | | $ | (974 | ) |
| 2011 | | | | | | | | | | | | | | | | |
| Electric margins | $ | 2,252 |
| | $ | 1,087 |
| | $ | 668 |
| | $ | (10 | ) | | $ | 3,997 |
| $ | 2,252 |
| | $ | 1,087 |
| | $ | (10 | ) | | $ | 3,329 |
|
| Natural gas margins | 79 |
| | 354 |
| | — |
| | (2 | ) | | 431 |
| 79 |
| | 354 |
| | (2 | ) | | 431 |
|
| Other revenues | 5 |
| | 1 |
| | 3 |
| | (9 | ) | | — |
| 5 |
| | 1 |
| | (6 | ) | | — |
|
| Other operations and maintenance | (934 | ) | | (640 | ) | | (285 | ) | | 39 |
| | (1,820 | ) | (934 | ) | | (640 | ) | | 12 |
| | (1,562 | ) |
| Impairment and other charges | (89 | ) | | — |
| | (37 | ) | | 1 |
| | (125 | ) | |
| Taum Sauk regulatory disallowance | | (89 | ) | | — |
| | — |
| | (89 | ) |
| Depreciation and amortization | (408 | ) | | (215 | ) | | (143 | ) | | (19 | ) | | (785 | ) | (408 | ) | | (215 | ) | | (20 | ) | | (643 | ) |
| Taxes other than income taxes | (296 | ) | | (129 | ) | | (24 | ) | | (8 | ) | | (457 | ) | (296 | ) | | (129 | ) | | (8 | ) | | (433 | ) |
| Other income and (expenses) | 51 |
| | 1 |
| | 1 |
| | (7 | ) | | 46 |
| 51 |
| | 1 |
| | (7 | ) | | 45 |
|
| Interest charges | (209 | ) | | (136 | ) | | (105 | ) | | (1 | ) | | (451 | ) | (209 | ) | | (136 | ) | | (42 | ) | | (387 | ) |
| Income (taxes) benefit | (161 | ) | | (127 | ) | | (32 | ) | | 10 |
| | (310 | ) | (161 | ) | | (127 | ) | | 34 |
| | (254 | ) |
| Net income (loss) | 290 |
| | 196 |
| | 46 |
| | (6 | ) | | 526 |
| |
| Noncontrolling interest and preferred dividends | (3 | ) | | (3 | ) | | (1 | ) | | — |
| | (7 | ) | |
| Net income (loss) attributable to Ameren Corporation | $ | 287 |
| | $ | 193 |
| | $ | 45 |
| | $ | (6 | ) | | $ | 519 |
| |
| 2010 | | | | | | | | | | |
| 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 | ) | |
| Impairment and other charges | — |
| | — |
| | (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 |
| |
| Income (loss) from continuing operations | | 290 |
| | 196 |
| | (49 | ) | | 437 |
|
| Income from discontinued operations, net of taxes | | — |
| | — |
| | 89 |
| | 89 |
|
| Net income | | 290 |
| | 196 |
| | 40 |
| | 526 |
|
| Net income attributable to noncontrolling interests – continuing operations | | (3 | ) | | (3 | ) | | — |
| | (6 | ) |
| Net income attributable to noncontrolling interests – discontinued operations | | — |
| | — |
| | (1 | ) | | (1 | ) |
| Net income attributable to Ameren Corporation | | $ | 287 |
| | $ | 193 |
| | $ | 39 |
| | $ | 519 |
|
Margins
The following table presents the favorable (unfavorable) variations by segment for 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, 20122013, 20112012, and 20102011. 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 may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
|
| | | | | | | | | | | | | | | | | | | |
| 2012 versus 2011 | Ameren Missouri | | Ameren Illinois Segment | | Merchant Generation | | Other(a) | | Ameren |
| Electric revenue change: | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (19 | ) | | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (20 | ) |
| Regulated rates: | | | | | | | | | |
| Base rates (estimate) | 102 |
| | — |
| | — |
| | — |
| | 102 |
|
| Formula ratemaking adjustment under IEIMA (estimate) | — |
| | (55 | ) | | — |
| | — |
| | (55 | ) |
Recovery of FAC under-recovery(c) | (47 | ) | | — |
| | — |
| | — |
| | (47 | ) |
| Off-system revenues (included in base rates) | (131 | ) | | — |
| | — |
| | — |
| | (131 | ) |
| FAC prudence review disallowance | 17 |
| | — |
| | — |
| | — |
| | 17 |
|
| Transmission services | 5 |
| | (1 | ) | | — |
| | (3 | ) | | 1 |
|
| Wholesale revenues | (13 | ) | | (6 | ) | | — |
| | — |
| | (19 | ) |
| Illinois pass-through power supply costs | — |
| | (154 | ) | | — |
| | (77 | ) | | (231 | ) |
| Energy efficiency programs and environmental remediation cost riders | — |
| | 11 |
| | — |
| | — |
| | 11 |
|
| Bad debt rider | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
| Hurricane Sandy relief cost recovery | 7 |
| | 10 |
| | — |
| | — |
| | 17 |
|
| Rate-regulated sales volume (excluding the impact of abnormal weather) | (6 | ) | | (3 | ) | | — |
| | — |
| | (9 | ) |
| Merchant Generation sales volume | — |
| | — |
| | (225 | ) | | — |
| | (225 | ) |
| Merchant Generation sales price changes, including hedge effect | — |
| | — |
| | (26 | ) | | — |
| | (26 | ) |
| Net unrealized MTM gains | — |
| | — |
| | 11 |
| | — |
| | 11 |
|
| Other | (5 | ) | | 2 |
| | (13 | ) | | (2 | ) | | (18 | ) |
| Total electric revenue change | $ | (90 | ) | | $ | (201 | ) | | $ | (253 | ) | | $ | (82 | ) | | $ | (626 | ) |
| Fuel and purchased power change: | | | | | | | | | |
| Fuel: | | | | | | | | | |
| Merchant Generation production volume and other | $ | — |
| | $ | — |
| | $ | 83 |
| | $ | — |
| | $ | 83 |
|
| Fuel, purchased power and transportation costs (included in base rates) | 106 |
| | — |
| | — |
| | — |
| | 106 |
|
Recovery of FAC under-recovery(c) | 47 |
| | — |
| | — |
| | — |
| | 47 |
|
| Net unrealized MTM gains (losses) | 1 |
| | — |
| | (23 | ) | | — |
| | (22 | ) |
| Price - Merchant Generation | — |
| | — |
| | (13 | ) | | — |
| | (13 | ) |
| Power purchase agreement settlement | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
| Merchant Generation purchased power and other | — |
| | — |
| | 56 |
| | 4 |
| | 60 |
|
| Transmission over-recovery | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
| Illinois pass-through power supply costs | — |
| | 154 |
| | — |
| | 77 |
| | 231 |
|
| Total fuel and purchased power change | $ | 178 |
| | $ | 148 |
| | $ | 103 |
| | $ | 81 |
| | $ | 510 |
|
| Net change in electric margins | $ | 88 |
| | $ | (53 | ) | | $ | (150 | ) | | $ | (1 | ) | | $ | (116 | ) |
| Natural gas margins change: | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (2 | ) | | $ | (10 | ) | | $ | — |
| | $ | — |
| | $ | (12 | ) |
| Base rates (estimate) | 2 |
| | 20 |
| | — |
| | — |
| | 22 |
|
| Rate redesign | (5 | ) | | — |
| | — |
| | — |
| | (5 | ) |
| Energy efficiency programs and environmental remediation cost riders | — |
| | 8 |
| | — |
| | — |
| | 8 |
|
| Bad debt rider | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) |
| Hurricane Sandy relief cost recovery | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
| Sales volume (excluding impact of abnormal weather) and other | 1 |
| | 8 |
| | — |
| | 1 |
| | 10 |
|
| Net change in natural gas margins | $ | (4 | ) | | $ | 24 |
| | $ | — |
| | $ | 1 |
| | $ | 21 |
|
|
| | | | | | | | | | | | | | | |
| 2013 versus 2012 | Ameren Missouri | | Ameren Illinois | | Other(a) | | Ameren |
| Electric revenue change: | | | | | | | |
Effect of weather (estimate)(b) | $ | (29 | ) | | $ | (11 | ) | | $ | — |
| | $ | (40 | ) |
| Base rates (estimate) | 178 |
| | 57 |
| | — |
| | 235 |
|
| Off-system sales and transmission services revenues (included in base rates) | 11 |
| | — |
| | — |
| | 11 |
|
| Transmission services revenue excluded from FAC until 2013 | (32 | ) | | — |
| | — |
| | (32 | ) |
Recovery of FAC under-recovery(c) | 67 |
| | — |
| | — |
| | 67 |
|
| FAC prudence review charge | (25 | ) | | — |
| | — |
| | (25 | ) |
| MEEIA (energy efficiency) | 72 |
| | — |
| | — |
| | 72 |
|
| Transmission services | — |
| | 25 |
| | 10 |
| | 35 |
|
| Gross receipts tax | 12 |
| | — |
| | — |
| | 12 |
|
| Illinois pass-through power supply costs | — |
| | (325 | ) | | (2 | ) | | (327 | ) |
| Hurricane Sandy relief recovery | (7 | ) | | (10 | ) | | — |
| | (17 | ) |
| Bad debt, energy efficiency programs, and environmental remediation cost riders | — |
| | (15 | ) | | — |
| | (15 | ) |
| Sales volume (excluding the impact of abnormal weather) | 4 |
| | 2 |
| | — |
| | 6 |
|
| Other | (4 | ) | | (1 | ) | | (2 | ) | | (7 | ) |
| Total electric revenue change | $ | 247 |
| | $ | (278 | ) | | $ | 6 |
| | $ | (25 | ) |
| Fuel and purchased power change: | | | | | | | |
| Energy costs included in base rates | $ | (89 | ) | | $ | — |
| | $ | — |
| | $ | (89 | ) |
Recovery of FAC under-recovery(c) | (67 | ) | | — |
| | — |
| | (67 | ) |
| FERC-ordered power purchase settlement | (24 | ) | | — |
| | — |
| | (24 | ) |
| Illinois pass-through power supply costs | — |
| | 325 |
| | 2 |
| | 327 |
|
| Total fuel and purchased power change | $ | (180 | ) | | $ | 325 |
| | $ | 2 |
| | $ | 147 |
|
| Net change in electric margins | $ | 67 |
| | $ | 47 |
| | $ | 8 |
| | $ | 122 |
|
| Natural gas margins change: | | | | | | | |
Effect of weather (estimate)(b) | $ | 3 |
| | $ | 14 |
| | $ | — |
| | $ | 17 |
|
| Base rates (estimate) | — |
| | 2 |
| | — |
| | 2 |
|
| Hurricane Sandy relief recovery | — |
| | (3 | ) | | — |
| | (3 | ) |
| Gross receipts tax | 1 |
| | 7 |
| | — |
| | 8 |
|
| Sales volume (excluding the impact of abnormal weather) and other | 4 |
| | 1 |
| | (1 | ) | | 4 |
|
| Net change in natural gas margins | $ | 8 |
| | $ | 21 |
| | $ | (1 | ) | | $ | 28 |
|
| | | 2011 versus 2010 | Ameren Missouri | | Ameren Illinois Segment | | Merchant Generation | | Other(a) | | Ameren | |
| 2012 versus 2011 | | Ameren Missouri | | Ameren Illinois | | Other(a) | | Ameren |
| Electric revenue change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (29 | ) | | $ | (7 | ) | | $ | — |
| | $ | — |
| | $ | (36 | ) | $ | (19 | ) | | $ | (1 | ) | | $ | — |
| | $ | (20 | ) |
| Regulated rates: | | | | | | | | | | |
| Base rates (estimate) | 172 |
| | 20 |
| | — |
| | — |
| | 192 |
| 102 |
| | (55 | ) | | — |
| | 47 |
|
| Off-system sales revenues (included in base rates) | | (131 | ) | | — |
| | — |
| | (131 | ) |
Recovery of FAC under-recovery(c) | 89 |
| | — |
| | — |
| | — |
| | 89 |
| (47 | ) | | — |
| | — |
| | (47 | ) |
| Off-system revenues included in base rates | 53 |
| | — |
| | — |
| | — |
| | 53 |
| |
| FAC prudence review disallowance | (17 | ) | | — |
| | — |
| | — |
| | (17 | ) | |
| FAC prudence review charge | | 17 |
| | — |
| | — |
| | 17 |
|
| Transmission services | 1 |
| | (4 | ) | | — |
| | 3 |
| | — |
| 5 |
| | (1 | ) | | 1 |
| | 5 |
|
| Wholesale revenues | (43 | ) | | 9 |
| | — |
| | — |
| | (34 | ) | (13 | ) | | (6 | ) | | — |
| | (19 | ) |
| Illinois pass-through power supply costs | — |
| | (112 | ) | | — |
| | (1 | ) | | (113 | ) | — |
| | (154 | ) | | 2 |
| | (152 | ) |
| Energy efficiency programs and environmental remediation cost riders | — |
| | 6 |
| | — |
| | — |
| | 6 |
| |
| Bad debt rider | — |
| | (17 | ) | | | | | | (17 | ) | |
| Rate-regulated sales volume (excluding the impact of abnormal weather) | (37 | ) | | (15 | ) | | — |
| | — |
| | (52 | ) | |
| Merchant Generation sales volume | — |
| | — |
| | 20 |
| | — |
| | 20 |
| |
| Merchant Generation sales price changes, including hedge effect | — |
| | — |
| | (74 | ) | | — |
| | (74 | ) | |
| Net unrealized MTM losses | (2 | ) | | — |
| | (16 | ) | | — |
| | (18 | ) | |
| Bad debt, energy efficiency programs and environmental remediation cost riders | | — |
| | 7 |
| | — |
| | 7 |
|
| Hurricane Sandy relief recovery | | 7 |
| | 10 |
| | — |
| | 17 |
|
| Sales volume (excluding the impact of abnormal weather) | | (6 | ) | | (3 | ) | | — |
| | (9 | ) |
| Other | 5 |
| | (1 | ) | | 4 |
| | 2 |
| | 10 |
| (5 | ) | | 2 |
| | (2 | ) | | (5 | ) |
| Total electric revenue change | $ | 192 |
| | $ | (121 | ) | | $ | (66 | ) | | $ | 4 |
| | $ | 9 |
| $ | (90 | ) | | $ | (201 | ) | | $ | 1 |
| | $ | (290 | ) |
| Fuel and purchased power change: | | | | | | | | | | | | | | | | |
| Fuel: | | | | | | | | | | |
| Merchant Generation production volume and other | $ | — |
| | $ | — |
| | $ | 11 |
| | $ | 1 |
| | $ | 12 |
| |
| Fuel, purchased power and transportation costs included in base rates | (84 | ) | | — |
| | — |
| | — |
| | (84 | ) | |
| Energy costs included in base rates | | $ | 106 |
| | $ | — |
| | $ | — |
| | $ | 106 |
|
Recovery of FAC under-recovery(c) | (89 | ) | | — |
| | — |
| | — |
| | (89 | ) | 47 |
| | — |
| | — |
| | 47 |
|
| Net unrealized MTM losses | — |
| | — |
| | (9 | ) | | 1 |
| | (8 | ) | |
| Price - Merchant Generation | — |
| | — |
| | (17 | ) | | — |
| | (17 | ) | |
| Merchant Generation purchased power and other | — |
| | — |
| | (31 | ) | | — |
| | (31 | ) | |
| Net unrealized MTM gains | | 1 |
| | — |
| | — |
| | 1 |
|
| FERC-ordered power purchase settlement | | 24 |
| | — |
| | — |
| | 24 |
|
| Transmission over-recovery | | — |
| | (6 | ) | | — |
| | (6 | ) |
| Illinois pass-through power supply costs | — |
| | 112 |
| | — |
| | 1 |
| | 113 |
| — |
| | 154 |
| | (2 | ) | | 152 |
|
| Total fuel and purchased power change | $ | (173 | ) | | $ | 112 |
| | $ | (46 | ) | | $ | 3 |
| | $ | (104 | ) | $ | 178 |
| | $ | 148 |
| | $ | (2 | ) | | $ | 324 |
|
| Net change in electric margins | $ | 19 |
| | $ | (9 | ) | | $ | (112 | ) | | $ | 7 |
| | $ | (95 | ) | $ | 88 |
| | $ | (53 | ) | | $ | (1 | ) | | $ | 34 |
|
| Natural gas margins change: | | | | | | | | | | | | | | | | |
Effect of weather (estimate)(b) | $ | (1 | ) | | $ | (5 | ) | | $ | — |
| | $ | — |
| | $ | (6 | ) | $ | (2 | ) | | $ | (10 | ) | | $ | — |
| | $ | (12 | ) |
| Base rates (estimate) | | 2 |
| | 20 |
| | — |
| | 22 |
|
| Rate redesign | | (5 | ) | | — |
| | — |
| | (5 | ) |
| Energy efficiency programs and environmental remediation cost riders | | — |
| | 8 |
| | — |
| | 8 |
|
| Bad debt rider | — |
| | (14 | ) | | — |
| | — |
| | (14 | ) | — |
| | (5 | ) | | — |
| | (5 | ) |
| Base rates (estimate) | 5 |
| | 3 |
| | — |
| | — |
| | 8 |
| |
| Energy efficiency programs and environmental remediation cost riders | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) | |
| Sales volume (excluding impact of abnormal weather) and other | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) | |
| Hurricane Sandy relief recovery | | — |
| | 3 |
| | — |
| | 3 |
|
| Sales volume (excluding the impact of abnormal weather) and other | | 1 |
| | 8 |
| | 1 |
| | 10 |
|
| Net change in natural gas margins | $ | 4 |
| | $ | (21 | ) | | $ | — |
| | $ | — |
| | $ | (17 | ) | $ | (4 | ) | | $ | 24 |
| | $ | 1 |
| | $ | 21 |
|
| |
| (a) | Includes amounts for other nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | Represents the estimated margin impact of changes in cooling and heating degree-days on electric and natural gas demand compared with the prior yearyear; this is based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories. |
| |
| (c) | Represents the change in the net fuel costs recovered under the FAC through customer rates, with corresponding offsets to fuel expense due to the amortization of a previously recorded regulatory asset. |
20122013 versus 20112012
Ameren Corporation
Ameren's electric margins decreasedincreased by $116$122 million,, or 3%4%, in 20122013 compared with 20112012. Ameren's natural gas margins increased by $28 million, or 6%, in 2013 compared with 2012. These results were primarily driven by Ameren Missouri and Ameren Illinois results, as discussed below. Ameren's electric margins also reflect the results of operations of ATXI. ATXI’s transmission revenues increased by $10 million in 2013 compared with 2012, due to the inclusion of its 2013 rate base investment in its forward-looking rate calculation.
Ameren Missouri
Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in net energy costs greater or less than the amount
set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews. Net energy cost includes fuel (coal, coal transportation, natural gas for generation, and enriched uranium), certain fuel additives, emission allowances, purchased power costs, transmission costs and revenues, and MISO costs and revenues, net of off-system sales revenues. The MoPSC's December 2012 electric order authorized the inclusion of fuel additive costs and transmission revenues in the FAC starting in 2013. Ameren Missouri accrues, as a regulatory asset, net energy costs that exceed the amount set in base rates (FAC under-recovery). Net recovery of these costs under the FAC through customer rates increased $67 million, in 2013 compared with 2012, with a corresponding offset to fuel expense to reduce the previously recognized FAC regulatory asset.
Ameren Missouri's electric margins increased by $67 million, or 3%, in 2013 compared with 2012. The following items had a favorable impact on Ameren Missouri's electric margins:
Higher electric base rates, effective January 2013 as a result of the December 2012 MoPSC electric rate order, which increased revenues by $178 million, partially offset by an increase in net energy costs of $78 million. The increase in net energy costs is the sum of the change in energy costs included in base rates (-$89 million) and the change in off-system sales and transmission services revenues (+$11 million) in the above table. Transmission services revenues were not included in the FAC in 2012 ($32 million). In 2013, transmission services revenues were included in the FAC, but were offset by the increase in base rates.
Higher revenues associated with the MEEIA energy efficiency program cost and lost revenue recovery mechanism ($35 million and $37 million, respectively), effective January 2013, which increased revenues by a combined $72 million. The lost revenue recovery mechanism helps compensate Ameren Missouri for lower sales from energy efficiency related volume reductions in current and future periods. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Missouri's MEEIA energy efficiency program. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs.
Increased gross receipts taxes, due primarily to the higher base rates, which increased revenues by $12 million. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.
Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes increased 1%, which increased revenues by $4 million.
The following items had an unfavorable impact on Ameren'sAmeren Missouri's electric margins in 2013 compared with 2012:
Weather conditions decreased revenues by $29 million. Summer temperatures in 2013 were cooler than the warmer-than-normal temperatures in 2012, as cooling degree-days decreased 22%. However, this was partially offset by winter temperatures in 2013 that were colder than the warmer-than-normal temperatures in 2012, as heating degree-days increased 35%.
A reduction in revenues resulting from a July 2013 MoPSC order. Ameren Missouri recorded a FAC prudence review charge for its estimated obligation to refund to its electric customers the earnings associated with sales recognized by Ameren Missouri from October 1, 2009, to May 31, 2011, which decreased revenues by $25 million. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for further information regarding the FAC prudence review charge.
The absence in 2013 of a reduction in purchased power expense as a result of a FERC-ordered refund received in 2012 from Entergy for a power purchase agreement that expired in 2009, which decreased margins by $24 million.
The absence in 2013 of recovery of labor and benefit costs for crews assisting with Hurricane Sandy power restoration in 2012, which decreased margins by $7 million and was
fully offset by a related decrease in operations and maintenance costs, with no overall impact on net income. Our costs related to storm assistance are reimbursed by the utilities receiving the assistance.
Ameren Missouri's natural gas margins increased by $8 million, or 11%, in 2013 compared with 2012. The following items had a favorable impact on Ameren Missouri's natural gas margins:
Excluding the estimated impact of abnormal weather, revenues increased by $4 million, driven by 11% higher natural gas transportation sales and 2% higher retail sales.
Weather conditions increased revenues by $3 million. Winter temperatures in 2013 were colder than the warmer-than-normal temperatures in 2012, as heating degree-days increased 35%.
Increased gross receipts taxes due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $1 million. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.
Ameren Illinois
Ameren Illinois has a cost recovery mechanism for power purchased on behalf of its customers. These pass-through power costs do not affect margins. Ameren Illinois' revenues associated with Illinois pass-through power supply costs decreased because of lower power prices on purchases and reduced volumes caused by customers who switched to alternative retail electric suppliers in 2013. This decrease in revenues was offset by a corresponding decrease in purchased power expense of $325 million.
Beginning in 2012, Ameren Illinois elected to participate in the performance-based formula ratemaking framework pursuant to the IEIMA. The IEIMA provides for an annual reconciliation of Ameren Illinois' electric distribution revenue requirement. As of each balance sheet date, Ameren Illinois records its estimate of the electric distribution revenue impact resulting from the reconciliation of the revenue requirement necessary to reflect the actual recoverable costs incurred for that year with the revenue requirement that was in effect for that year. See Operations and Maintenance Expenses in this section for further information regarding the revenue requirement. If the current year's revenue requirement is greater than the revenue requirement customer rates were based upon, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional costs from customers within the next two years. If the current year's revenue requirement is less than the revenue requirement customer rates were based upon, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within the next two years. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.
Ameren Illinois' electric margins increased by $47 million, or
5%, in 2013 compared with 2012. The following items had a favorable impact on Ameren Illinois' electric margins:
Decreased utilization of Merchant Generation's energy centers, primarily due to lower spot market prices, resulted in a decline in sales volume, which decreased revenues by $225 million. The decline was mitigated by a related $83 milliondecrease in production volume and other costs and a $56 milliondecrease in purchased power and other costs.
The electricElectric delivery service formula ratemaking adjustment at Ameren Illinois,adjustments resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA, which decreasedincreased revenues by $57 million. The adjustments were primarily caused by increased rate base, a higher allowed return on equity, and higher recoverable costs.
Transmission revenues increased by $25 million due to the implementation of a 2013 forward-looking rate calculation which incorporated the rate base increase in 2013, pursuant to a 2012 FERC order. In 2012, rates were based on a historical period.
The following items had an unfavorable impact on Ameren Illinois' electric margins in $552013 compared with 2012:
A decrease in recovery of bad debt, energy efficiency program costs, and environmental remediation costs through rate-adjustment mechanisms, which decreased revenues by $15 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting decrease in bad debt, energy efficiency, and environmental remediation costs.
Weather conditions decreased revenues by $11 million. Summer temperatures in 2013 were cooler than the warmer-than-normal temperatures in 2012, as cooling degree-days decreased 21%. However, this was partially offset by winter temperatures in 2013 that were colder than warmer-than-normal temperatures in 2012, as heating degree-days increased 29%.
The absence in 2013 of recovery of labor and benefit costs for crews assisting with Hurricane Sandy power restoration in 2012, which decreased margins by $10 million and was fully offset by a related decrease in operations and maintenance costs, with no overall impact on net income. Our costs related to storm assistance are reimbursed by the utilities receiving the assistance.
Ameren Illinois' natural gas margins increased by $21 million, or 6%, in 2013 compared with 2012. The following items had a favorable impact on Ameren Illinois' natural gas margins:
Weather conditions increased revenues by $14 million. Winter temperatures in 2013 were colder than warmer-than-normal temperatures in 2012, as heating degree-days increased 29%.
Increased gross receipts taxes due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $7 million. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.
Increased natural gas rates effective in late January 2012, which increased revenues by $2 million.
Ameren Illinois' natural gas margins were unfavorably impacted by the absence in 2013 of recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy power restoration in 2012, which decreased margins by $3 million
and was fully offset by a related decrease in operations and maintenance costs, with no overall impact on net income. Our costs related to storm assistance are reimbursed by the utilities receiving the assistance.
2012 versus 2011
Ameren Corporation
Ameren's electric margins increased by $34 million, or 1%, in 2012 compared with 2011. Ameren's natural gas margins increased by $21 million, or 5%, in 2012 compared with 2011. These results were primarily driven by Ameren Missouri and Ameren Illinois results, as discussed below.
Ameren Missouri
Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in net energy costs greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudence reviews. Net energy cost includes fuel (coal, coal transportation, natural gas for generation, and enriched uranium), emission allowances, purchased power costs, transmission costs, and MISO costs and revenues, net of off-system sales revenues. The MoPSC's December 2012 electric order authorized the inclusion of fuel additive costs and transmission revenues in the FAC starting in 2013. Ameren Missouri accrues, as a regulatory asset, net energy costs that exceed the amount set in base rates (FAC under-recovery). Net recovery of these costs under the FAC through customer rates decreased $47 million in 2012 compared with 2011, with a corresponding offset to fuel expense to reduce the previously recognized FAC regulatory asset.
Ameren Missouri's electric margins increased by $88 million, or 4%, in 2012 compared with 2011. The following items had a favorable impact on Ameren Missouri's electric margins:
Higher electric base rates, effective July 2011 as a result of the 2011 MoPSC electric rate order, which increased revenues by $102 million, partially offset by an increase in net energy costs of $25 million. The increase in net energy costs is the sum of the change in energy costs included in base rates (+$106 million) and the change in off-system sales revenues (-$131 million) in the above table.
Reduced purchased power expense as a result of a FERC-ordered refund received from Entergy in 2012 relating to a power purchase agreement that expired in 2009, which increased margins by $24 million.
The absence in 2012 of a reduction in revenues recorded in 2011 resulting from the MoPSC's April 2011 FAC prudence review order. Ameren Missouri recorded a FAC prudence review charge of $17 million in 2011 for its estimated obligation to refund to its electric customers the earnings associated with sales recognized during the period from March 1, 2009, to September 30, 2009.
The recovery of labor and benefit costs for crews assisting with Hurricane Sandy power restoration, which increased revenues by $7 million and was fully offset by a related
increase in operations and maintenance costs, with no overall impact on net income.
Higher transmission services revenues, primarily due to two transmission projects that went into service in the second half of 2011 and were included in transmission rates in 2012, which increased revenues by $5 million.
Summer temperatures in 2012 were comparable to 2011, as cooling degree-days increased 1%. However, summer temperatures in Ameren Missouri's service territory in 2012 were the warmest on record with 25% more cooling degree-days than normal.
The following items had an unfavorable impact on Ameren Missouri's electric margins in 2012 compared with 2011:
Weather conditions decreased revenues by $19 million. Winter temperatures in 2012 were warmer than the near-normal temperatures in 2011, as heating degree-days decreased 16%.
The inclusion of wholesale sales in the FAC as an offset to fuel costs beginning July 31, 2011, which decreased revenues by $13 million.
Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined by 1%, partially attributable to energy efficiency measures and customer conservation efforts, which decreased revenues by $6 million.
Ameren Missouri's natural gas margins decreased by $4 million, or 5%, in 2012 compared with 2011. The following items had an unfavorable impact on Ameren Missouri's natural gas margins:
Rate redesign, implemented as a result of the natural gas delivery service rate order that became effective in late February 2011, which allowed Ameren Missouri to recover more of its non-PGA residential revenues through a fixed monthly charge, with the remaining amounts recovered based on sales volumes, which resulted in revenues being recovered more evenly throughout the year. Revenues decreased by $5 million because the rate redesign was not in effect for the first two months of 2011.
Weather conditions decreased revenues by $2 million. Winter temperatures in 2012 were warmer than the near-normal temperatures in 2011, as heating degree-days decreased 16%.
Ameren Missouri's natural gas margins were favorably affected by an increase in rates that became effective in February 2011, which increased margins by $2 million.
Ameren Illinois
Ameren Illinois' revenues associated with Illinois pass-through power supply costs decreased because of lower power prices on purchases and reduced volumes caused by customers who switched to alternative retail electric suppliers. This decrease in revenues was offset by a corresponding decrease in purchased power expense of $154 million.
Ameren Illinois' electric margins decreased by $53 million, or 5%, in 2012 compared with 2011. The following items had an unfavorable impact on Ameren Illinois' electric margins:
Electric delivery service formula ratemaking adjustment resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA, which decreased revenues by $55 million. The reduction in revenues for 2012 was primarily caused by a lower allowed return on equity as the ICC's 2010 electric rate order resulted in a higher return on equity than the 2012 formula rate calculation allowed. The 2012 formula for the return on equity pursuant to the IEIMA was equal to the 2012 average of the monthly yields of 30-year United States treasury bonds plus 590 basis points. The return on equity included in Ameren Illinois' 2010 electric rate order was 10.2% whereas the 2012 IEIMA formula resulted in an 8.8% return on equity with the ability to earn above or below this amount
by 50 basis points. The 2012 revenue requirement reconciliation included the impact of the September 2012 ICC order, which reduced revenues from October through December 2012 by $8 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Lower sales prices at Merchant Generation, including hedge effect, primarily driven by lower market prices, partially offset by a favorable settlement with a large customer, which decreased revenues by $26 million.
Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a 15%decrease in heating degree-days, which decreased revenues by $20 million.
Reduced capacity revenues at Merchant Generation, driven by low MISO capacity market prices and the expiration of older, higher-priced agreements, contributed to the $13 milliondecrease in Merchant Generation's other revenues.
The inclusion of wholesale sales in Ameren Missouri's FAC as an offset to fuel costs beginning July 31, 2011, decreased revenues by $13 million.
Higher fuel prices in the Merchant Generation segment, primarily due to higher commodity costs associated with new coal supply agreements, decreased margins by $13 million.
Net unrealized MTM activity, principally at the Merchant Generation segment, related to fuel-related contracts were partially offset by MTM activity related to nonqualifying power hedges, which decreased margins by $11 million.
Excluding the estimated impact of abnormal weather, rate-regulated sales volumes were flat overall, but were down 1% in the higher-margin residential sector, partially attributable to energy efficiency measures and customer conservation efforts, which decreased revenues by $9 million.
Lower wholesale distribution revenues, at Ameren Illinois, primarily due to lower demand and the recognition of a reserve for revenues subject to a refund as a result of a November 2012 FERC administrative law judge's decision, which in total decreased revenues by $6 million.$6 million. See Note 2 -– Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Ameren Illinois accrues, as a regulatory asset or liability, transmission costs that are greater than or less than the amount set in transmission rates (transmission under-recovery or over-recovery). In 2012, Ameren Illinois over-recovered from customers its transmission costs by $6 million.$6 million. As a result, Ameren Illinois reduced a previously recognized regulatory asset that had been established for an under-recovery of costs.
Decreased recoveries through Ameren Illinois' bad debt rider, which reducedExcluding the estimated impact of abnormal weather, rate-regulated sales volumes increased by 1%, driven largely by the lower-margin industrial sector. However, margins decreased $3 million due to volume declines in the higher-margin residential and commercial sectors, partially attributable to energy efficiency measures and customer conservation efforts.
Weather conditions decreased revenues by $4 million. See Other Operations and Maintenance Expense$1 million. Winter temperatures in this section for additional information on a relatedoffsetting decrease2012 were warmer than the near-normal temperatures in bad debt expense.
The following items had a favorable impact on Ameren'sAmeren Illinois' electric margins in 2012 compared with 2011:2011:
Higher electric base rates at Ameren Missouri, effective July 2011, which increased revenues by $102 million, offset by an increase in net base fuel expense of $25 million, which was a result of higher net base fuel cost rates approved in the 2011 MoPSC rate order. The change in net base fuel expense was the sum of the change in fuel, purchased power, and transportation costs included in base rates (+$106 million) and the change in off-system revenues (-$131 million) in the above table. See below for additional details regarding the FAC.
Reduced purchased power expense at Ameren Missouri as a result of a FERC-ordered refund from Entergy received in 2012 relating to a power purchase agreement that expired in 2009, which increased margins by $24 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Absence in 2012 of a reduction in Ameren Missouri's revenues recorded in 2011 resulting from the MoPSC's April 2011 FAC prudence review order for the period from March 1, 2009, to September 30, 2009, which increased revenues by $17 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Recoveryrecovery of labor and benefit costs at Ameren Missouri and Ameren Illinois associated withfor crews assisting with Hurricane Sandy power restoration, which increased revenues by $17$10 million, and was fully offset by operations and maintenance costs, with no overall impact on net income. Our
Increased recovery of bad debt, energy efficiency program costs, and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $7 million. See Other Operations and Maintenance Expenses in this section for information on the related offsetting increase in bad debt, energy efficiency, and environmental remediation costs.
Summer temperatures in 2012 were comparable to storm assistance are reimbursed2011, as cooling degree-days increased by 2%. However, summer
temperatures in Ameren Illinois' service territory in 2012 were the utilities receiving the assistance.
warmest on record, with 24% more cooling degree-days than normal.Ameren Illinois' natural gas margins increased by $24 million, or 7%, in 2012 compared with 2011. The following items had a favorable impact on Ameren Illinois' natural gas margins:
Higher natural gas rates effective January 2012, which increased revenues by $20 million.
Increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustmentcost recovery mechanisms, at Ameren Illinois, which increased revenues by $11 million.$8 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.
Summer weather conditions in 2012 that were comparable to 2011, as evidenced by an increase of 1% in cooling degree-days. However, weather conditions in Ameren's service territory in 2012 were the warmest on record, with 25%more cooling degree-days than normal.
Ameren's revenues associated with Illinois pass-through power supply costs decreased$231 million because of lower power prices on sales and customers switching to alternative retail electric suppliers. This decrease in revenues was offset by a corresponding net decrease in purchased power expense, including Merchant Generation which supplied $77 million more power to Ameren Illinois in 2012, which was eliminated for Ameren consolidated purposes.
Ameren Missouri has a FAC cost recovery mechanism that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel, emission allowances, purchased power costs, transmission costs and MISO costs and revenues, net of off-system revenues, greater or less than the amount set in base
rates without a traditional rate proceeding, subject to MoPSC prudency reviews. The MoPSC's December 2012 order authorized the inclusion of fuel additive costs and transmission revenues in the FAC starting in 2013. Ameren Missouri accrues, as a regulatory asset, fuel and purchased power costs that are greater than the amount set in base rates (FAC under-recovery). Net recovery of fuel costs under the FAC through customer rates decreased by $47 million in 2012, as compared with 2011, with corresponding offsets to fuel expense to reduce the previously recognized FAC regulatory asset. The MoPSC's December 2012 order also authorized the inclusion of fuel additive costs and transmission revenues in the FAC starting in 2013.
Ameren's natural gas margins increased by $21 million, or 5%, in 2012 compared with 2011. The following items had a favorable impact on Ameren's natural gas margins:
Higher natural gas rates effective February 2011 at Ameren Missouri and effective January 2012 at Ameren Illinois increased revenues by $22 million.
Higher sales volume and other primarily at Ameren Illinois due to increased transportation sales from two large industrial customers and 1% higher residential sales volumes, excluding the impact of abnormal weather, which combined increased margins by $10 million.
Increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms at Ameren Illinois, which increased revenues by $8 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.
Recovery of labor and benefit costs at Ameren Illinois associated with crews assisting with Hurricane Sandy gas service restoration, which increased revenues by $3 million, and was fully offset by operations and maintenance costs, with no overall impact on net income. Our costs related to storm assistance are reimbursed by the utilities receiving the assistance.
The following items had an unfavorable impact on Ameren's natural gas margins:
Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by decrease in heating degree-days of 15%, which decreased margins $12 million.
Decreased recoveries through Ameren Illinois' bad debt rider, which decreased margins by $5 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.
Rate redesign at Ameren Missouri, implemented as a result of the natural gas delivery service rate order that became effective in late February 2011, allowed Ameren Missouri to recover more of its non-PGA residential revenues through a fixed monthly charge, with the remaining amounts recovered based on sales volumes, which resulted in revenues being recovered more evenly throughout the year. Revenues
decreased$5 million, because this rate redesign was not in effect for the first two months of 2011.
Ameren Missouri
Ameren Missouri has a FAC cost recovery mechanism, which is discussed in the Ameren margin section above.
Ameren Missouri's electric margins increased by $88 million, or 4%, in 2012 compared with 2011. The following items had a favorable impact on Ameren Missouri's electric margins:
Higher electric base rates, effective July 2011, which increased revenues by $102 million, offset by an increase in net base fuel expense of $25 million, which was a result of higher net base fuel cost rates approved in the 2011 MoPSC rate order. The change in net base fuel expense was the sum of the change in fuel, purchased power and transportation costs included in base rates (+$106 million) and the change in off-system revenues (-$131 million) in the above table.
Reduced purchased power expense as a result of a FERC-ordered refund received from Entergy in 2012 relating to a power purchase agreement that expired in 2009, which increased margins by $24 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Absence in 2012 of a reduction in revenues recorded in 2011 resulting from the MoPSC's FAC prudence review order the period from March 1, 2009, to September 30, 2009, which increased revenues by $17 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy power restoration, which increased revenues by $7 million and was fully offset by operations and maintenance costs with no overall impact on net income.
Higher transmission services revenues primarily due to two transmission projects that went into service in second half of 2011 and were included in transmission rates in 2012, which increased revenues by $5 million.
Summer weather conditions in 2012 were comparable to 2011, as evidenced by an increase of 1% in cooling degree-days. However, weather conditions in Ameren Missouri's service territory in 2012 were the warmest on record with 25%more cooling degree-days than normal.
The following items had an unfavorable impact on Ameren Missouri's electric margins in 2012 compared with 2011:
Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a 16%decrease in heating degree-days, which decreased revenues by $19 million.
The inclusion of wholesale sales in the FAC as an offset to fuel costs beginning July 31, 2011, decreased revenues by $13 million.
Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes that declined by 1%, partially
attributable to energy efficiency measures and customer conservation efforts, which decreased revenues by $6 million.
Ameren Missouri's natural gas margins decreased by $4 million, or 5%, in 2012 compared with 2011. The following items had an unfavorable impact on Ameren Missouri's natural gas margins:
Rate redesign, as a result of the natural gas delivery service rate order that became effective in late February 2011, allowed Ameren Missouri to recover more of its non-PGA residential revenues through a fixed monthly charge, with the remaining amounts recovered based on sales volumes, which resulted in revenues being recovered more evenly throughout the year. Revenues decreased by $5 million, because the rate redesign was not in effect for the first two months of 2011.
Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by decrease in heating degree-days of 16%, which decreased margins by $2 million.
Ameren Missouri's natural gas margins were favorably affected by an increase in rates that became effective in February 2011, which increased margins by $2 million.
Ameren Illinois
Ameren Illinois 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 to alternative retail electric suppliers and customer usage. Ameren Illinois does not generate earnings based on the resale of power but rather on the delivery of power.
Ameren Illinois' electric margins decreased by $53 million, or 5%, in 2012 compared with 2011. The following items had an unfavorable impact on electric margins:
The formula ratemaking adjustment related to an annual reconciliation of the revenue requirement pursuant to the IEIMA decreased revenues by $55 million. The reduction in revenues for 2012 was primarily caused by a lower allowed return on equity as the ICC's 2010 electric rate order resulted in a higher return on equity than the 2012 formula rate calculation allowed. The 2012 formula for the return on equity is equal to the 2012 average of monthly yields of 30-year United States treasury bonds plus 590 basis points. The return on equity included in Ameren Illinois' 2010 electric rate order was 10.2% whereas the 2012 IEIMA formula resulted in an 8.8% return on equity with the ability to earn above or below this amount by 50 basis points. The 2012 revenue requirement reconciliation included the impact of the September ICC order, which reduced revenues from October through December 2012 by $8 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Lower wholesale distribution revenues, primarily due to lower demand, and the recognition of a reserve for revenues subject to a refund as a result of a November 2012 FERC administrative law judge's decision, which in total decreased revenues by $6 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Ameren Illinois accrues, as a regulatory asset or liability, transmission costs that are greater than or less than the amount set in transmission rates (transmission under-recovery or over-recovery). In 2012, Ameren Illinois over-recovered from customers its transmission costs by $6 million. As a result, Ameren Illinois reduced a previously recognized regulatory asset that had been established for an under-recovery of costs.
Decreased recoveries through Ameren Illinois' bad debt rider, which decreased margins by $4 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.
Excluding the estimated impact of abnormal weather, rate-regulated sales volumes that increased by 1%, driven largely by the lower-margin industrial sector; however, margins decreased$3 million due to volume declines in the higher-margin residential and commercial sectors, partially attributable to energy efficiency measures and customer conservation efforts.
Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a decrease of 14% in heating degree-days, which decreased revenues by $1 million.
The following items had a favorable impact on Ameren Illinois' electric margins in 2012 compared with 2011:
Increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $11 million. See Other Operations and Maintenance Expenses in this section for information on the related offsetting increase in energy efficiency and environmental remediation costs.
Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy power restoration, which increased revenues by $10 million, and was fully offset by operations and maintenance costs with no overall impact on net income.
Summer weather conditions in 2012 were comparable to 2011, as evidenced by an increase of 2% in cooling degree-days. However, weather conditions in Ameren Illinois' service territory in 2012 were the warmest on record with 24%more cooling degree-days than normal.
Ameren Illinois' natural gas margins increased by $24 million, or 7%, in 2012 compared with 2011. The following items had a favorable impact on Ameren Illinois' natural gas margins:
Increase in natural gas rates effective January 2012, which increased revenues by $20 million.
Increased recovery of energy efficiency program costs and
environmental remediation costs through Illinois cost recovery mechanisms, which increased revenues by $8 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.
Higher sales volume and other primarily due to increased transportation sales from two large industrial customers and 1% higher residential sales volumes, excluding the impact of abnormal weather, which combined together increased margins by $8 million.
$8 million.RecoveryThe recovery of labor and benefit costs associated withfor crews assisting with Hurricane Sandy gas service restoration, which increased revenues by $3$3 million,, and was fully offset by a related increase in operations and maintenance costs, with no overall impact on net income.
The following items had an unfavorable impact on Ameren Illinois' natural gas margins in 2012 compared with 2011:
Weather conditions decreased revenues by $10 million. Winter weather conditionstemperatures in 2012 were mild compared to near normal conditionswarmer than the near-normal temperatures in 2011, as evidenced by a decrease in heating degree-days of decreased 14%, which decreased margins $10 million.
Decreased recoveries through Ameren Illinois'the bad debt rider, which reduced margins by $5 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.
Merchant Generation
Merchant Generation's electric margins decreased by $150 million, or 22%, in 2012 compared with 2011. The following items had an unfavorable impact on electric margins:
Decreased energy center utilization, primarily due to lower spot market prices and an EEI sales contract in 2011 that was not supplied in 2012. Consequently, Merchant Generation's sales volume declined, which decreased revenues by $225 million. This decline was mitigated by an $83 milliondecrease in production volume and other costs and a $56 milliondecrease in purchased power and other costs. Merchant Generation's average capacity factor decreased to 66%, in 2012, compared with 72%, in 2011, because of lower power prices. Merchant Generation's equivalent availability factor remained unchanged at 85% in 2012 and 2011.
Lower sales prices, including hedge effect, primarily driven by lower market prices, partially offset by a favorable settlement with a large customer, which decreased revenues by $26 million.
Reduced capacity revenues, driven by low MISO capacity market prices and the expiration of older, higher-priced agreements, contributed to the $13 milliondecrease in other revenues.
Higher fuel prices, primarily due to higher commodity costs associated with new coal supply agreements, which decreased margins by $13 million.
Net unrealized MTM activity, primarily on fuel-related
contracts, were partially offset by nonqualifying power hedges, which decreased margins by $12 million.
2011 versus 2010
Ameren
Ameren's electric margins decreased by $95 million, or 2%, in 2011 compared with 2010. The following items had an unfavorable impact on Ameren's electric margins:
Lower sales prices, including hedge effects, at the Merchant Generation segment due to reductions in higher-margin sales 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 $74 million.
Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes that declined 1%, attributable to continued economic pressure, energy efficiency measures and customer conservation efforts, which decreased revenues by $52 million.
Lower wholesale sales at Ameren Missouri due to a reduction in customers, the expiration of favorably priced contracts and the inclusion of revenues from the remaining contracts as an offset to fuel costs in the FAC beginning July 31, 2011, which decreased revenues by $43 million.
Winter weather conditions in 2011 were near normal compared to a somewhat colder-than-normal 2010, as evidenced by a 6% decrease in heating degree-days, which decreased revenues by $36 million.
Net unrealized MTM losses principally at the Merchant Generation segment, related to nonqualifying power hedges and fuel-related contracts, which decreased margins by $26 million.
A $17 million reduction in revenues recorded in 2011, at Ameren Missouri resulting from the MoPSC's order with respect to its FAC disallowance for the period from March 1, 2009, to September 30, 2009. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, for further information regarding the FAC prudence review.
Decreased recovery of prior years' bad debt expense at Ameren Illinois, through the Illinois bad debt rider, effective March 2010, which decreased margins by $17$5 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.
6% higher fuel prices in the Merchant Generation segment, primarily due to higher commodity and transportation costs associated with new supply contracts, which decreased margins by $17 million.
The following items had a favorable impact on Ameren's electric margins in 2011 compared with 2010:
Higher electric base rates at Ameren Missouri, effective June 2010 and July 2011, which increased revenues by $172 million, offset by an increase in net base fuel expense of $31 million, which was a result of higher net base fuel cost rates approved in the 2010 and 2011 MoPSC rate
orders and higher fuel and transportation costs. The change in net base fuel expense was the sum of the change in the fuel, purchased power and transportation costs included in base rates (-$84 million) and the change in off-system revenues (+$53 million) in the above table. See below for additional details regarding the FAC.
Energy center utilization at Merchant Generation in 2011 was comparable with 2010. Merchant Generation's higher sales volume increased electric revenues by $20 million, which was mostly offset by a related increase of $20 million in higher net fuel and purchased power costs. Merchant Generation's purchased power and other costs increased $31 million because of the availability of lower-priced power on the open market; however, Merchant Generation's production volume and other costs decreased $11 million because of utilization of a lower-cost mix of energy centers. Merchant Generation's average capacity factor remained unchanged at 72% in 2011 and 2010, but Merchant Generation's equivalent availability factor decreased to 85% in 2011, compared with 87% in 2010.
Higher electric delivery service rates at Ameren Illinois, effective in early May and November 2010, which increased margins by $20 million.
Higher wholesale revenues at Ameren Illinois, primarily due to higher rates effective April 2011, which increased revenues by $9 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms at Ameren Illinois, which increased margins by $6 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.
Ameren's revenues associated with Illinois pass-through power supply costs decreased $113 million because of lower power prices on sales primarily to nonaffiliated parties. These revenues were offset by a corresponding net decrease in purchased power.
Net recovery of fuel costs under the FAC through customer rates increased by $89 million in 2011, as compared with 2010, with corresponding offsets to fuel expense to reduce the previously recognized FAC regulatory asset.
Ameren's natural gas margins decreased by $17 million, or 4%, in 2011 compared with 2010. The following items had an unfavorable impact on Ameren's natural gas margins:
Decreased recovery of prior years' bad debt expense through the Illinois bad debt rider at Ameren Illinois, effective March 2010, which decreased margins by $14 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.
Unfavorable winter weather conditions, as evidenced by a 6% decrease in heating degree-days, which decreased
revenues by $6 million. Compared to normal, Ameren experienced 3% fewer heating degree-days in 2011.
4% lower native load sales volumes, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, attributable to economic pressure, decreased margins by $4 million.
Ameren's natural gas margins were favorably affected by $8 million in 2011 compared with 2010 because of higher natural gas rates effective February 2011 at Ameren Missouri and effective in May and November 2010 at Ameren Illinois.
Ameren Missouri
Ameren Missouri has a FAC cost recovery mechanism, which is outlined in the Ameren margin section above.
Ameren Missouri's electric margins increased by $19 million, or 1%, in 2011 compared with 2010. Ameren Missouri's electric margins were favorably affected by higher electric base rates, effective in June 2010 and July 2011 ($172 million), offset by increased net base fuel expense of $31 million, which was a result of higher net base fuel cost rates approved in the 2010 and 2011 MoPSC rate orders and higher fuel and transportation costs. The change in net base fuel expense is the sum of the change in fuel, purchased power and transportation costs included in base rates (-$84 million) and the change in off-system revenues (+$53 million) in the above table.
The following items had an unfavorable impact on Ameren Missouri's electric margins in 2011 compared with 2010:
Lower wholesale sales due to a reduction in customers, the expiration of favorably priced contracts, and the inclusion of revenues from the remaining contracts as an offset to fuel costs in the FAC beginning July 31, 2011, which decreased revenues by $43 million.
Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined by 1%, attributable to continued economic pressure, energy efficiency measures, and customer conservation efforts, which decreased revenues by $37 million.
Winter weather conditions in 2011 were near normal compared to a somewhat colder-than-normal 2010, as evidenced by a 7% decrease in heating degree-days, which decreased revenues by $29 million.
A $17 million reduction in revenues recorded in 2011 resulting from the MoPSC's order with respect to its FAC disallowance for the period from March 1, 2009 to September 30, 2009. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, for further information regarding the FAC prudence review.
Ameren Missouri's natural gas margins increased by $4 million, or 5%, in 2011 compared with 2010. Ameren Missouri's natural gas margins were favorably affected by higher natural gas rates, effective February 2011, which increased margins by $5 million.
Ameren Illinois
Ameren Illinois 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 to alternative retail electric suppliers and their usage. Ameren Illinois does not generate earnings based on the resale of power, but rather on the delivery of energy.
Ameren Illinois' electric margins decreased by $9 million, or 1%, in 2011 compared with 2010. The following items had an unfavorable impact on electric margins:
Decreased recovery of prior years' bad debt expense through the Illinois bad debt rider, effective March 2010, which decreased margins by $17 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.
Continued economic pressure, energy efficiency measures, and customer conservation efforts, which decreased revenues by $15 million.
Winter weather conditions in 2011 were near normal compared to a somewhat colder-than-normal 2010, as evidenced by a 5% decrease in heating degree-days, which decreased revenues by $7 million.
The following items had a favorable impact on Ameren Illinois' electric margins in 2011 compared with 2010:
Higher electric delivery service rates, effective in May and November 2010, which increased margins by $20 million.
Higher wholesale revenues, primarily due to higher rates effective April 2011, which increased revenues by $9 million. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms, which increased margins by $6 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.
Ameren Illinois' natural gas margins decreased by $21 million, or 6%, in 2011 compared with 2010. The following items had an unfavorable impact on Ameren Illinois' natural gas margins:
Decreased recovery of prior years' bad debt expense under the Illinois bad debt rider, effective March 2010, which decreased margins by $14 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense.
Unfavorable winter weather conditions, as evidenced by a 5% decrease in heating degree-days, decreased revenues by $5 million. However, compared to normal, Ameren Illinois experienced in 2011 a 2% decrease in heating degree-days.
Native load sales volumes declined by 4%, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, attributable to continued economic pressure, which decreased revenues by $4 million.
Ameren Illinois' gas margins were favorably affected by $3 million due to higher natural gas rates effective in May and November 2010.
Merchant Generation
Merchant Generation's electric margins decreased by $112 million, or 14%, in 2011 compared with 2010. The following items had an unfavorable impact on electric margins:
Lower sales prices, including hedge effects, due to reductions in higher-margin sales 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 revenues by $74 million.
Net unrealized MTM activity 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, and on nonqualifying power hedges, which decreased margins by $25 million.
6% higher fuel prices, primarily due to higher commodity and transportation costs associated with escalations in existing transportation agreements and new commodity supply agreements, which decreased margins by $17 million.
Merchant Generation's electric margins were favorably affected by higher sales volume, which increased electric revenues by $20 million. Higher revenues were largely offset by a related increase in net fuel and purchased power costs of $20 million. Purchased power and other costs increased $31 million due to the availability of cheaper power on the open market; however, production volume and other costs decreased $11 million due to usage of a lower-cost mix of energy centers. Energy center utilization in 2011 was comparable with 2010. The average capacity factor remained unchanged at 72% in 2011 and 2010, but equivalent availability factor decreased to 85% in 2011, compared with 87% in 2010.
Other Operations and Maintenance Expenses
20122013 versus 20112012
Ameren Corporation
Other operations and maintenance expenses decreasedincreased by $68$106 million in 20122013 compared with 2011.2012 primarily due to increased expenses at Ameren Missouri and Ameren Illinois as discussed below. Additionally, there was a $9 million increase in unallocated Ameren (parent) other operations and maintenance expenses.
Ameren Missouri
Other operations and maintenance expenses increased by $88 million in 2013. The following items reducedincreased other operations and maintenance expenses between years:
A $40$35 million decreaseincrease in energy efficiency program costs
due to the requirements of MEEIA, which became effective in rates in January 2013. These costs were offset by increased electric revenues recovered through customer billings, with no overall effect on net income.
A $31 million increase in energy center maintenance costs, primarily due to $38 million in costs for the scheduled 2013 Callaway energy center refueling
and maintenance costs as thereoutage. There was no outage in 2012.
A $33 The 2013 increase was partially offset by a $7 million decreasereduction in storm-related repair costs due to fewer major storms in 2012.boiler outages at coal-fired energy centers.
A $29$14 million decreaseincrease in plant maintenanceemployee benefit costs, primarily due to higher pension expense and increased amortization of prior-year pension deferrals from the December 2011 closurepension and postretirement benefit cost tracker, each as a result of two Merchant Generation coal-fired energy centers.the 2012 MoPSC electric order. These increased employee benefit costs were offset by increased electric revenues from customer billings, with no overall effect on net income.
A $28$9 million decreaseincrease in employee severancestorm-related repair costs, primarily due to major storms in 2013. A portion of these costs, $7 million, were offset by electric revenues recovered through customer billings.
A $6 million increase in bad debt expense due to reduced customer collections and higher customer rates in 2013.
Other operations and maintenance expenses decreased between years because of the non-recurrenceabsence in 2013 of a $6 million charge recorded in 2012 for a canceled project.
Ameren Illinois
Pursuant to the provisions of the voluntary separation program offeredIEIMA, recoverable electric distribution costs incurred during the year that are not recovered through riders are included in Ameren Illinois’ revenue requirement reconciliation, which results in a corresponding adjustment to electric operating revenues, with no overall effect on net income. These recoverable electric distribution costs include other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, interest charges, and income taxes.
Other operations and maintenance expenses increased by Ameren Missouri$9 million in 2013. The following items increased other operations and Ameren Services in 2011.maintenance expenses between years:
A $20An $11 million decreaseincrease in labor costs, primarily because staff reductions at Ameren Missouri more than offsetof staff additions at Ameren Illinois due to comply with the requirements of the IEIMA.
An $8 million increase in non-storm-related electric distribution maintenance expenditures, primarily related to increased vegetation management work.
A $15$3 million increase in other transmission and distribution expenses, primarily because of expenses for natural gas pipeline integrity compliance.
The following items decreased other operations and maintenance expenses between years:
A $7 million decrease in bad debt expense due to improved customer collections
adjustments under the Ameren Illinois bad debt rider of $4 million.rider. Expenses recorded under the Ameren Illinois bad debt rider mechanism were recovered through customer billings, and so were offset by increased revenues, with no overall effect on net income.
A $10$7 million favorable change in unrealized net MTM gains between years, resulting from changes in the market value of investments used to support Ameren's deferred compensation plans.
Disciplined cost management efforts to align spending with regulatory outcomes, policies, and economic conditions.
The following items increased other operations and maintenance expenses between years:
A $19 million increasedecrease in energy efficiency and environmental remediation costs at Ameren Illinois.costs. These costs were recovered through customer billings and so were offset by increaseddecreased electric and natural gas revenues from customer billings, with no overall impacteffect on net income.
An $18 million charge in 2012 for canceled projects at Ameren Missouri and Merchant Generation.
A $12 million increase in employee benefit costs, primarily due to increased pension expense.
A $12 million increase in non-storm-related distribution maintenance expenditures due, in part, to mild winter weather in 2012 at Ameren Illinois allowing crews to complete more maintenance projects.
A $10 million increase in transmission and distribution expenses, primarily at Ameren Illinois, because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA, and pipeline integration compliance.
A $10 million increase in Ameren's stock-based compensation expense. See Note 12 - Stock-based Compensation under Part II, Item 8, of this report for additional information.
A $6 million increase in outside legal fees, primarily for legal consultation regarding strategic matters.
Variations in other operations and maintenance expenses in Ameren's business segments and for the Ameren Companies
between 2012 andversus 2011 were as follows:
Ameren MissouriCorporation
Other operations and maintenance expenses decreased by $107$51 million in 2012 compared with 2011, primarily due to a reduction in Ameren Missouri expenses, which was partially offset by an increase in Ameren Illinois expenses as discussed below. Also, there was a $10 million increase in stock-based compensation expense at Ameren (parent).
Ameren Missouri
Other operations and maintenance expenses decreased by $107 million in 2012.
The following items reduced other operations and maintenance expenses between years:
A $40 million decrease in Callaway energy center refueling and maintenance costs, as there was no outage in 2012.
A $27 million decrease in employee severance costs due to the voluntary separation program in 2011.
A $25 million reduction in other labor costs, primarily because of staff reductions.
A $19 million decrease in storm-related repair costs, due to fewer major storms in 2012.
A $6 million favorable change in unrealized net MTM gains between years, resulting from changes in the market value of investments used to support Ameren's deferred compensation plans.
A $6 million decrease in bad debt expense due to improved customer collections.
A $4 million decrease in non-storm-related distribution maintenance expenditures, primarily due to lower repair spending.
Disciplined cost management efforts to align spending with regulatory outcomes, policies, and economic conditions.
Other operations and maintenance expenses increased between years because of a $6 million charge in 2012 for a canceled project.
Ameren Illinois
Other operations and maintenance expenses increased by $44$44 million in 2012.
The following items increased other operations and maintenance expenses between years:
A $19 million increase in energy efficiency and
environmental remediation costs. These costs which are discussed above.were offset by increased electric and natural gas revenues from customer billings, with no overall effect on net income.
A $16 million increase in non-storm-related electric distribution maintenance expenditures due, in part, to mild winter weather in 2012 allowing crews to complete more maintenance projects.
A $15 million increase in other labor costs, primarily because of staff additions due to comply with the requirements of the IEIMA.
An $11 million increase in transmission and distribution expenses, primarily because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA, and pipeline integrationintegrity compliance.
A $6 million increase in employee benefit costs, primarily due to increased pension expense.
The following items reduced other operations and maintenance expenses between years:
A $14 million decrease in storm-related repair costs, due to fewer major storms in 2012.
A $9 million decrease in bad debt expense, including $5 million due to improved customer collections and $4 million due to adjustments related to prior years under the bad debt rider.
Merchant Generation
Other operations and maintenance expenses decreased by $26 million in 2012 in the Merchant Generation segment, as reduced plant maintenance costs of $32 million, due to the December 2011 closure of two coal-fired energy centers, fewer outages, as well as disciplined cost management more than offset charges for canceled projects of $12 million and an increase in employee benefit costs of $6 million, primarily due to increased pension expense.
2011 versus 2010
Ameren Corporation
Other operations and maintenance expenses were comparable between 2011 and 2010.
The following items reduced other operations and maintenance expenses between years:
Charges in 2010 of $22 million due to canceled or unrecoverable projects at Ameren Missouri that did not recur in 2011.
A decrease of $20 million in plant maintenance costs, primarily because the scope of the outages in 2011 was not as extensive as in 2010. Costs associated with the 2011 refueling and maintenance outage at Ameren Missouri's Callaway energy center were consistent with costs incurred for the 2010 refueling and maintenance outage.
A $17 million decrease in bad debt expense. Bad debt expense decreased primarily because of adjustments Expenses recorded under the Ameren Illinois bad debt rider mechanism.mechanism were recovered through customer billings, and so were offset by decreased revenues, with no overall effect on net income.
A $5 million decrease in employee benefitTaum Sauk Regulatory Disallowance
2012 versus 2011
Ameren Missouri
During 2011, the MoPSC issued an electric rate order that disallowed the recovery of all costs primarily because of adjustments under Ameren Missouri's pension and postretirement benefit cost tracker.
Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.
The following items increased other operations and maintenance expenses between years:
A $34 million increase in storm-related repairenhancements, or costs due to major storms in 2011.
Recognition of $28 million of employee severance coststhat would have been incurred absent the breach, related to the voluntary separation offersrebuilding of the Taum Sauk energy center in excess of the amount recovered from property insurance. Consequently, Ameren and Ameren Missouri recorded a pretax charge to eligibleearnings of $89 million.
Depreciation and Amortization
2013 versus 2012
Ameren Corporation
Depreciation and amortization expenses increased by $33 million in 2013 compared with 2012 due primarily to increased expenses at Ameren Missouri and Ameren Services employees in 2011.
A reduction in other operations and maintenance expenses in 2010 by $11 million for a May 2010 MoPSC rate order, which resulted in the recording of regulatory assets related
to 2009 employee severance costs and storm costs.
An unfavorable change of $9 million in unrealized net MTM adjustments between years, resulting from changes in the market value of investments used to support Ameren's deferred compensation plans.
A $5 million increase in Ameren Illinois' energy efficiency and environmental remediation costs.
Variations in other operations and maintenance expenses in Ameren's business segments and for the Ameren Companies between 2011 and 2010 were as follows:
Ameren Missouri
Other operations and maintenance expenses were comparable between years.
The following items increased other operations and maintenance expenses between years:
Recognition of $27 million of employee severance costs related to the voluntary separation plan in 2011.
A $21 million increase in storm-related repair costs, due to major storms in 2011.
A reduction in other operations and maintenance expenses in 2010 by $11 million for the May 2010 MoPSC rate order discussed above.
An unfavorable change of $5 million in unrealized net MTM adjustments between years, 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 years:
Plant maintenance costs decreased by $23 million, primarily because the scope of the outages in 2011 was not as extensive as in 2010.
Charges in 2010 of $22 million because of canceled or unrecoverable projects.
A $9 million decrease in employee benefit costs, primarily because of adjustments under the pension and postretirement benefit cost tracker.
Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions.
Ameren Illinois
Other operations and maintenance expenses were comparable between years.
The following items increased other operations and maintenance expenses between years:
A $13 million increase in storm-related repair costs, due to major storms in 2011.
Energy efficiency and environmental remediation costs increased by $5 million, as discussed above.
Injuries and damages expenses were higher by $4 million because of increased claims.below.
ExpensesAmeren Missouri
Depreciation and amortization expenses increased by $14 million in 2013 compared with 2012, primarily because of $3increased depreciation expense of $6 million associated withrelated to electric distribution capital additions and because of increased amortization expense of $6 million related to the December 2012 MoPSC electric rate caseorder resulting in 2011higher amortization of pre-MEEIA energy efficiency program costs, which were written-offreflected in electric rates effective in January 2013.
Ameren Illinois
Depreciation and amortization expenses increased by $22 million in 2013 compared with 2012, primarily because the rate case was withdrawn after passage of the IEIMA.
Anew electric depreciation rates, which increased depreciation expense by $17 million, as a result of a reduction in other operationsthe useful lives of existing electric meters that are being replaced with advanced metering infrastructure pursuant to the IEIMA, and maintenancebecause of electric general capital additions, which increased depreciation expense by $6 million.
2012 versus 2011
Ameren Corporation
Depreciation and amortization expenses increased by $30 million in 2010 of $3 million for2012 compared with 2011 due to increased expenses at Ameren Missouri and Ameren Illinois as discussed below. There was a May 2010 ICC rate order, which resulted in the recording of a regulatory asset related to 2009 employee severance costs.
The following items reduced other operations and maintenance expenses between years:
A $19$5 million reduction in bad debt expense. Adjustmentsdepreciation and amortization expenses at Ameren Services due to the retirement of $31computer equipment in 2011.
Ameren Missouri
Depreciation and amortization expenses increased by $32 million underin 2012 compared with 2011, primarily because of increased depreciation and amortization expenses associated with new scrubbers at the bad debt rider mechanismSioux energy center (depreciation expense began with the effective date of the July 2011 electric rate order) and other capital additions.
Ameren Illinois
Depreciation and amortization expenses increased by $6 million in 2012 compared with 2011, primarily because of transmission and distribution infrastructure additions.
Taxes Other Than Income Taxes
2013 versus 2012
Ameren Corporation
Taxes other than income taxes increased by $15 million in 2013 compared with 2012 due primarily to increased expenses at Ameren Missouri and Ameren Illinois as discussed below.
Ameren Missouri
Taxes other than income taxes increased by $15 million,
primarily due to an increase in gross receipts taxes of $13 million as a result of increased sales. These increased gross receipts taxes were partially offset by higher uncollectible expense.
A reduction of $5 millionincreased gross receipts tax revenues, with no overall effect on net income. See Excise Taxes in non-storm-related distribution maintenance expenditures due, in part, to cost management efforts.
Merchant Generation
Other operations and maintenance expenses were comparable between years in the Merchant Generation segment. Increased employee benefit costs, primarily pension costs, and higher plant maintenance costs resulting from increased planned outages at AERG mitigated the favorable impact of property sale gains at Genco.
Impairment and Other Charges
The following table summarizes impairment and other charges for the years ended December 31, 2012, 2011, and 2010:
|
| | | | | | | | | | | | | | | |
| | Long-lived Assets and Related Charges | | Goodwill | | Emission Allowances | | Total |
| 2012: | | | | | | | |
Ameren(a) | $ | 2,578 |
| | $ | — |
| | $ | — |
| | $ | 2,578 |
|
| 2011: | | | | | | | |
Ameren(a) | 123 |
| | — |
| | 2 |
| | 125 |
|
| AMO | 89 |
| | — |
| | — |
| | 89 |
|
| 2010: | | | | | | | |
Ameren(a) | $ | 101 |
| | $ | 420 |
| | $ | 68 |
| | $ | 589 |
|
| |
(a) | Includes amounts for registrant and nonregistrant subsidiaries. |
See Note 1 -– Summary of Significant Accounting Policies Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 17 - Impairment and Other Charges under Part II, Item 8, of this report for additional information.
Ameren Illinois
Taxes other than income taxes increased by $2 million, primarily because of an increase in gross receipts taxes of $7 million as a result of increased natural gas sales, partially offset by a decrease in property taxes of $6 million, primarily as a result of two electric distribution tax credits received in 2013. The goodwillincreased gross receipts taxes were offset by increased gross receipts tax revenues, with no overall effect on net income. See Excise Taxes in Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report for additional information.
2012 versus 2011
Ameren Corporation
Taxes other than income taxes increased by $10 million in 2012 compared with 2011 due to increased expenses at Ameren Missouri as discussed below.
Ameren Missouri
Taxes other than income taxes increased by $8 million in 2012, because of higher property taxes resulting from increased state and local assessments in 2012, the recording of a refund for protested distributable taxes in 2011, and the subsequent recording in December 2012 based on the MoPSC electric rate order to return this refund to customers. These unfavorable items more than offset a decrease in payroll taxes between years.
Ameren Illinois
Taxes other than income taxes were comparable between years, as a reduction in gross receipts taxes resulting from decreased sales offset higher property taxes due to increased rates.
Other Income and Expenses
2013 versus 2012
Ameren Corporation
Other income, net of expenses, increased by $10 million in 2013 compared with 2012 primarily due to decreased expenses at Ameren Illinois as discussed below.
Ameren Missouri
Other income, net of expenses, decreased by $2 million, primarily due to a decrease in interest income resulting from the absence in 2013 of a 2012 interest payment received from
Entergy as part of the FERC-ordered refund related to a power purchase agreement that expired in 2009, partially offset by decreased donations. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for more information about the Entergy refund received in 2012.
Ameren Illinois
Other income, net of expenses, increased by $11 million, primarily due to decreased donations because of the absence in 2013 of the one-time $7.5 million contribution to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA in connection with participation in the formula ratemaking process in 2012 and to increased interest income, primarily related to the IEIMA's 2013 revenue requirement reconciliation adjustment.
2012 versus 2011
Ameren Corporation
Other income, net of expenses, decreased by $12 million in 2012 compared with 2011 primarily due to increased expenses at Ameren Illinois as discussed below.
Ameren Missouri
Other income, net of expenses, was comparable between years. Increased donations offset an increase in interest income, resulting from the interest paid by Entergy on the amount it overcharged Ameren Missouri under a power purchase agreement. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for further information on the power purchase agreement with Entergy.
Ameren Illinois
Ameren Illinois had net other expenses of $10 million in 2012, compared with net other income of $1 million in 2011. Donations increased by $10 million because of a one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and a $1 million annual donation for customer assistance programs pursuant to the IEIMA, because Ameren Illinois participated in the formula ratemaking process in 2012.
Interest Charges
2013 versus 2012
Ameren Corporation
Interest charges increased by $6 million in 2013 compared with 2012 because increases at Ameren Illinois more than offset decreases at Ameren Missouri as discussed below. Additionally, there was a $5 million increase in interest charges associated with uncertain tax positions at Ameren (parent). See Note 13 – Income Taxes under Part II, Item 8, of this report for information regarding uncertain tax positions.
Ameren Missouri
Interest charges decreased by $13 million, primarily because of a decrease in interest charges associated with uncertain tax positions and the favorable net impact of the September 2012 repurchase of $71 million of 6.00% senior secured notes, $121 million of 6.70% senior secured notes, and $57 million of 5.10% senior secured notes and issuance of $485 million of 3.90% senior secured notes.
Ameren Illinois
Interest charges increased by $14 million, primarily due to a charge recorded in 2013 as a result of the ICC's December 2013 electric rate order, which disallowed the recovery from customers of a portion of debt premium costs incurred in 2012. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for additional information. Also, interest charges increased due to interest applied to the regulatory liability for the 2012 revenue requirement reconciliation. Partially offsetting the increase was the favorable net impact of the August 2012 repurchase of $87 million of 9.75% senior secured notes and $194 million of 6.25% senior secured notes and issuance of $400 million of 2.70% senior secured notes.
2012 versus 2011
Ameren Corporation
Interest charges increased by $5 million in 2012 compared with 2011 primarily because increases at Ameren Missouri more than offset a decrease in interest charges at Ameren Illinois. Additionally, reduced credit facility borrowings and commercial paper issuances at Ameren resulted in a $2 million reduction in interest charges.
Ameren Missouri
Interest charges increased by $14 million in 2012, primarily because Ameren Missouri no longer recorded an allowance for funds used during construction for pollution control equipment installed at its Sioux energy center after the cost of the equipment was placed in customer rates beginning July 31, 2011, and an increase in interest charges associated with uncertain tax positions.
Ameren Illinois
Interest charges decreased by $7 million in 2012, primarily because of the redemption of $150 million of senior secured notes in June 2011.
Income Taxes
The following table presents effective income tax rates for Ameren's business segments and for the Ameren Companies for the years ended December 31, 2013, 2012, and 2011:
|
| | | |
| | 2013 | 2012 | 2011 |
| Ameren | 38% | 37% | 37% |
| Ameren Missouri | 38% | 37% | 36% |
| Ameren Illinois | 40% | 40% | 39% |
See Note 13 – Income Taxes under Part II, Item 8, of this report for information regarding reconciliations of effective income tax rates.
2013 versus 2012
Ameren Corporation
Ameren’s effective tax rate was higher primarily because of items detailed at Ameren Missouri below.
Ameren Missouri
Ameren Missouri’s effective tax rate was higher primarily because of the decreased impact of the amortization of property-related regulatory assets and liabilities and an increase in nondeductible expenses, partially offset by an increase in reserves for uncertain tax positions in 2012.
Ameren Illinois
Ameren Illinois’ effective tax rate was comparable between 2013 and 2012. The increased impact of the amortization of property-related regulatory assets and liabilities was offset by the decreased impact of investment tax credit amortization.
2012 versus 2011
Ameren Corporation
Ameren's effective tax rate was comparable between 2012 and 2011. The effective tax rate increases for Ameren Missouri and Ameren Illinois noted below were offset primarily by a decrease related to permanent tax benefits from company-owned life insurance. Variations in effective tax rates at Ameren Missouri and Ameren Illinois between 2012 and 2011 are noted below.
Ameren Missouri
Ameren Missouri's effective tax rate was higher primarily because of an increase in reserves for uncertain tax positions in 2012, compared with a decrease in 2011. Additionally, the effective tax rate increased because of the decreased impact of the amortization of property-related regulatory assets and liabilities, and estimated tax credits on higher pretax income in 2012 compared with 2011.
Ameren Illinois
Ameren Illinois' effective tax rate was higher primarily because of the favorable impact of recording the adjustment to deferred tax assets due to the Illinois statutory income tax rate increase in 2011.
Income (Loss) from Discontinued Operations, Net of Taxes
See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for information regarding Ameren’s exit from the Merchant Generation business and the discontinued operations disclosures relating to that business.
Ameren’s loss from discontinued operations, net of taxes, was $223 million in 2013, compared with a loss from discontinued operations, net of taxes, of $1.5 billion in 2012. Ameren’s income from discontinued operations, net of taxes, was $89 million in 2011. Ameren's losses from discontinued operations were impacted by asset impairments in 2011 and 2012, and a loss on disposal in 2013 as discussed below.
Loss on Disposal
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. On December 2, 2013, Ameren completed the divestiture of New AER to IPH. On January 31, 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital.
Upon completion of the divestiture of New AER, Ameren finalized its loss on disposal. Ameren received no cash proceeds from IPH for the divestiture of New AER. Ameren recorded a pretax charge to earnings related to the New AER divestiture of $201 million for the year ended December 31, 2013. The ultimate loss on disposal may differ as a result of the finalization of the working capital adjustment within 120 days of close.
In 2013, Ameren adjusted the accumulated deferred income taxes on its consolidated balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER. This change in basis resulted in a discontinued operations deferred tax expense of $99 million, which was partially offset by the expected tax benefits of $86 million related to the pretax loss from discontinued operations including the loss on disposal, during the year ended December 31, 2013. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon the resolution of tax matters under IRS audit, including the adoption of recently issued guidance from the IRS related to tangible property repairs and other matters. As a result, tax expense and benefits ultimately realized in discontinued operations may differ materially from those recorded as of December 31, 2013.
As the Elgin, Gibson City, and Grand Tower gas-fired energy center disposal group continued to meet the
discontinued operations criteria at December 31, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. In December 2012, as discussed below, Ameren recorded a noncash long-lived asset impairment charges did not result in a violation of any Ameren or Ameren subsidiary debt covenants or counterparty agreements.
Ameren Corporation
In 2012, Ameren recorded noncash pretax impairment charges of $2.6 billioncharge to reduce the carrying valuesvalue of all but one of Merchant Generation's coalAER’s energy centers, including the Elgin, Gibson City, and naturalGrand Tower gas-fired energy centers. centers, to their estimated fair values under the accounting guidance for held and used assets. Ameren did not record any additional impairment relating to the Elgin, Gibson City, and Grand Tower energy centers for the year ended December 31, 2013. On January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital for a total purchase price of $168 million, before consideration of a net working capital adjustment. Ameren will not recognize a gain from the sale to Rockland Capital for any value in excess of its $137.5 million carrying value for this disposal group since any excess amount that Medina Valley may receive, net of taxes and other expenses, over the carrying value will ultimately be paid to Genco pursuant to the transaction agreement with IPH.
Long-lived Asset Impairments
Ameren recorded long-lived asset impairments under held and used accounting guidance related to its merchant generation business totaling $2.6 billion in 2012 and $30 million in 2011, before taxes.
In December 2012, Ameren determinedconcluded that it intends to, and it is probable that it will, exitthe Merchant Generation segment was no longer a core component of its Merchant Generation
future business before the end of the previously estimated useful lives of that business' long-lived assets.strategy. As a result of the December 2012 determination,decision that Ameren concludedintended to, and that it was probable that it would, exit the Merchant Generation segment before the end of the Merchant Generation long-lived assets' previously estimated useful lives, Ameren determined that estimated undiscounted cash flows throughduring the period in which Ameren expectsit expected to continue to have a significant economic interest inown certain energy centers would be insufficient to recover the carrying value of those energy centers. Accordingly, Ameren recorded a noncash pretax impairment charge of $1.95 billion in December 2012 to reduce the carrying values of all of the Merchant Generation's coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values. The estimated undiscounted cash flows of the Joppa coal-fired energy center exceeded its carrying value andvalue; therefore, the Joppa coal-fired energy center was unimpaired. Following the impairment charge, the net book value of Ameren's Merchant Generation long-lived assets was $748 million as of December 31, 2012.
Key assumptions used in the determination of estimated undiscounted cash flows of Ameren's Merchant Generation segment's long-lived assets tested for impairment included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and terminal year earnings multiples, were used to estimate the fair value of each energy center. These assumptions are subject to a high degree of judgment and
complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. For the fourth quarter 2012 long-lived asset impairment test, Ameren used a discount rate of 10% for the coal-fired energy centers, 10.5% for the combined cycle energy center, and 11.5% for natural gas-fired energy centers, used a terminal year earnings multiple ranging from 4.5 to 6 depending on the energy center's fuel type and installed pollution control equipment, and estimated that the duration of ownership for each energy center was less than five years, with one energy center's duration of ownership being less than two years. Holding all other assumptions constant, if the discount rate had been one percentage point higher, or if the terminal year earnings multiple had been one point lower, or if the duration of ownership for each energy center was one year less than estimated, the fourth quarter 2012 impairment charge would have been $30 million to $110 million higher. As discussed above, the Joppa coal-fired energy center's estimated undiscounted cash flows exceeded its carrying value; however, using the same assumptions to estimate the fair value of that energy center would result in an estimated fair value that approximated its carrying value as of December 31, 2012.
In early 2012, the observable market price for power for delivery in 2012that year and in future years in the Midwest sharply declined below 2011 levels, primarily because of declining natural gas prices and the impact of the stay of the CSAPR. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012.
The sharp decline in the market price of power in early 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco's Newton energy center scrubber project, caused Merchant GenerationAmeren to evaluate, during the first quarter of 2012, whether the carrying values of itsMerchant Generation coal-fired energy centers were recoverable. AERG's Duck Creek energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG's Duck Creekthat energy center to its estimated fair value during the first quarter of 2012. Similar types of assumptions described above for the fourth quarter 2012 long-lived asset impairment test were used in this first quarter 2012 test. In this first quarter 2012 test, Ameren used a discount rate of 9.5% and estimated each energy center's useful life based on its physical life. The estimated useful life assumption in this first quarter 2012 test was based on energy center specific facts.
The 2012 long-lived asset impairment charges are expected to reduce 2013 depreciation expense by approximately $75 million.
In December 2011, Genco ceased operations of its Meredosia and Hutsonville energy centers. As a result, Ameren recorded a noncash pretax asset impairment chargescharge of $26 million to reduce the carrying value of the Meredosia and Hutsonville energy centers to their estimated fair values and a $4 million impairment of materials and supplies, and $4 million for severance costs.
During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused Ameren to evaluate if the carrying value of its Merchant Generation energy centers were recoverable. The Meredosia energy center's carrying value and Medina Valley energy center's carrying value exceeded their estimated undiscounted future cash flows. As a result, during 2010, Ameren recorded a noncash pretax asset impairment charge of $101 million to reduce the carrying value of the Meredosia and Medina Valley energy centers to their estimated fair values. In 2012, Ameren sold the Medina Valley energy center and recognized a $10 million gain on the sale.
Prior to 2010, Merchant Generation expected to use its SO2 emission allowances for ongoing operations. In July 2010, the EPA issued the proposed CSAPR, which would have restricted the use of existing SO2 emission allowances. As a result, Merchant Generation no longer expected that all of its SO2 emission allowances would be used in operations. Therefore, during 2010, Ameren recorded a noncash pretax impairment charge of $68 million to reduce the carrying value of the Merchant Generation segment's SO2 emission allowances to their estimated fair value. In July 2011, the EPA issued the final CSAPR, which created new allowances for SO2 and NOx emissions and restricted the use of pre-existing SO2 and NOx allowances to the acid rain program and to the NOx budget trading program, respectively. As a result, observable market
prices for existing emission allowances declined materially. Ameren recorded a noncash pretax impairment charge of $2 million in 2011 relating to Merchant Generation's emission allowances.
During 2010, Ameren also recorded a noncash pretax goodwill impairment charge of $420 million, which represented all of the goodwill assigned to Ameren's Merchant Generation reporting unit. The goodwill impairment recorded in 2010 was caused by a sustained decline in market prices for electricity, by industry market multiples becoming observable at lower levels than previously estimated, and by the possibility that more stringent environmental regulations would be enacted.
Ameren Missouri
During 2011, the MoPSC issued an electric rate order that disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of the amount recovered from property insurance. Consequently, Ameren and Ameren Missouri each recorded a pretax charge to earnings of $89 million.
Depreciation and Amortization
2012 versus 2011
Ameren Corporation
Ameren's depreciation and amortization expenses decreased by $10 million in 2012 compared with 2011, primarily because of decreased depreciation and amortization expense in the Merchant Generation segment noted below and a $5 million reduction in depreciation and amortization expenses at Ameren Services, due to the retirement of computer equipment in 2011, partially offset by increases at Ameren Missouri and Ameren Illinois noted below.
Variations in depreciation and amortization expenses in Ameren's business segments and for the Ameren Companies between 2012 and 2011 were as follows:
Ameren Missouri
Depreciation and amortization expenses increased by $32 million in 2012, primarily because of increased depreciation and amortization expenses associated with the new scrubbers at the Sioux energy center (depreciation expense began with the effective date of the July 2011 electric rate order) and other capital additions.
Ameren Illinois
Depreciation and amortization expenses increased by $6 million in 2012, primarily due to transmission and distribution infrastructure additions.
Merchant Generation
Depreciation and amortization expenses decreased by $41supplies.
million in 2012, primarily because of a 2011 change in estimates related to asset retirement obligations and the closure of two coal-fired energy centers in December 2011. Additionally, the long-lived asset impairments recorded during the first and fourth quarters of 2012 caused a reduction in the carrying value of net plant assets and thus depreciation expense.
2011 versus 2010
Ameren Corporation
Ameren's depreciation and amortization expenses increased by $20 million in 2011 compared with 2010, because of items noted below. Partially mitigating these increases was an $8 million reduction in depreciation and amortization expenses at Ameren Services, primarily because computer equipment became fully-depreciated during 2011.
Variations in depreciation and amortization expenses in Ameren's business segments and for the Ameren Companies between 2011 and 2010 were as follows:
Ameren Missouri
Depreciation and amortization expenses increased by $26 million in 2011, primarily because of increased depreciation and amortization expenses resulting from the installation of the new scrubbers at the Sioux energy center and other capital additions. Additionally, an increase in Ameren Missouri's annual depreciation rates as a result of the 2010 MoPSC electric rate order resulted in higher depreciation and amortization expenses.
Ameren Illinois
Depreciation and amortization expenses increased by $5 million in 2011, primarily because of capital additions.
Merchant Generation
Depreciation and amortization expenses were comparable between years in the Merchant Generation segment.
Taxes Other Than Income Taxes
2012 versus 2011
Ameren Corporation
Taxes other than income taxes increased by $11 million in 2012 compared with 2011 primarily because of items noted below at Ameren Missouri.
Variations in taxes other than income taxes in Ameren's business segments and for the Ameren Companies between 2012 and 2011 were as follows:
Ameren Missouri
Taxes other than income taxes increased by $8 million in 2012, because of higher property taxes resulting from increased state and local assessments in 2012, the recording of a refund for
protested distributable taxes in 2011, and the subsequent recording in December 2012 based on the MoPSC electric rate order to return this refund to customers. These unfavorable items more than offset a decrease in payroll taxes between years.
Ameren Illinois
Taxes other than income taxes were comparable between years, as a reduction in gross receipts taxes resulting from decreased sales offset higher property taxes due to increased rates.
Merchant Generation
Taxes other than income taxes were comparable between years.
2011 versus 2010
Ameren Corporation
Taxes other than income taxes increased by $8 million in 2011 compared with 2010, primarily because of items noted below at Ameren Missouri.
Variations in taxes other than income taxes in Ameren's business segments and for the Ameren Companies between 2011 and 2010 were as follows:
Ameren Missouri
Taxes other than income taxes increased by $11 million in 2011, primarily because of increased property taxes, due to higher state and local assessments and higher tax rates, and to higher gross receipts taxes from increased revenues.
Ameren Illinois
Taxes other than income taxes were comparable between years. Increased property taxes in 2011, primarily due to higher tax rates, were mitigated by lower corporate franchise taxes in 2011 as a result of the Ameren Illinois Merger.
Merchant Generation
Taxes other than income taxes were comparable between years.
Other Income and Expenses
2012 versus 2011
Ameren Corporation
Other income, net of expenses, decreased by $12 million in 2012 compared with 2011, primarily due to increased expenses at Ameren Illinois as discussed below.
Variations in other income, net of expenses, in Ameren's business segments and for the Ameren Companies between 2012 and 2011 were as follows:
Ameren Missouri
Other income, net of expenses, was comparable between years. Increased donations offset an increase in interest income, resulting from the interest paid by Entergy on the amount it overcharged Ameren Missouri under a power purchase agreement. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for further information on the power purchase agreement with Entergy.
Ameren Illinois
Ameren Illinois had net other expenses of $10 million in 2012, compared with net other income of $1 million in 2011. Donations increased by approximately $10 million because of a one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and a $1 million annual donation for customer assistance programs pursuant to the IEIMA, because Ameren Illinois participated in the formula ratemaking process in 2012.
Merchant Generation
Other income, net of expenses, was comparable between years.
2011 versus 2010
Ameren Corporation
Other income, net of expenses, decreased by $11 million in 2011 compared with 2010, primarily because of items noted below.
Variations in other income, net of expenses, in Ameren's business segments and for the Ameren Companies between 2011 and 2010 were as follows:
Ameren Missouri
Other income, net of expenses, decreased by $19 million in 2011, primarily because of reduced allowance for equity funds used during construction. Allowance for equity funds used during construction was higher in 2010, primarily due to the new scrubbers being constructed at Ameren Missouri's Sioux energy center, which were placed in service in late 2010.
Ameren Illinois
Other income, net of expenses, increased by $7 million in 2011, primarily because of reduced expenses associated with customer assistance programs.
Merchant Generation
Other income, net of expenses, was comparable between years.
Interest Charges
2012 versus 2011
Ameren Corporation
Interest charges decreased by $3 million in 2012 compared with 2011, primarily because decreases at Ameren Illinois and in the Merchant Generation segment more than offset an increase in interest charges at Ameren Missouri. In addition, reduced credit facility borrowings and commercial paper issuances at Ameren lowered interest charges.
Variations in interest charges in Ameren's business segments and for the Ameren Companies between 2012 and 2011 were as follows:
Ameren Missouri
Interest charges increased by $14 million in 2012, primarily because Ameren Missouri no longer recorded an allowance for funds used during construction for pollution control equipment installed at its Sioux energy center when the cost of the equipment was placed in customer rates beginning July 31, 2011, and an increase in interest charges associated with uncertain tax positions.
Ameren Illinois
Interest charges decreased by $7 million in 2012, primarily because of the redemption of $150 million of senior secured notes in June 2011.
Merchant Generation
Interest charges decreased by $10 million in 2012, primarily because of increased capitalized interest due to the Newton energy center scrubber project.
2011 versus 2010
Ameren Corporation
Interest charges decreased by $46 million in 2011 compared with 2010, because of items noted below and because of reduced credit facility borrowings at Ameren.
Variations in interest charges in Ameren's business segments and for the Ameren Companies between 2011 and 2010 were as follows:
Ameren Missouri
Interest charges decreased by $4 million in 2011, primarily because of a reduction in interest charges associated with uncertain tax positions of $6 million, the redemption of $66 million of subordinated deferrable interest debentures in September 2010, and reduced amortization of credit facility fees. Offsetting these favorable items was a reduction in interest charges in 2010 due to the May 2010 MoPSC electric rate order. The rate order resulted in a reduction of interest charges of $10 million in 2010, through the recording of a regulatory asset for recovery of bank credit facility fees incurred in 2009.
Ameren Illinois
Interest charges decreased by $7 million in 2011, primarily because of the redemption of $150 million of senior secured notes in June 2011 and the redemption of $40 million of first mortgage bonds in September 2010.
Merchant Generation
Interest charges decreased by $28 million in 2011 because of the maturity and repayment of $200 million of Genco senior unsecured notes in November 2010 and because of reduced intercompany borrowings at AERG.
Income Taxes
The following table presents effective income tax rates for Ameren's business segments and for the Ameren Companies for the years ended December 31, 2012, 2011, and 2010:
|
| | | |
| | 2012 | 2011 | 2010 |
| Ameren | 41% | 37% | 68%(a) |
| Ameren Missouri | 37 | 36 | 35 |
| Ameren Illinois | 40 | 39 | 39 |
| Merchant Generation | 40 | 41 | (2)(b) |
| |
(a) | The impact of a goodwill impairment charge, which is not deductible for income tax purposes, increased the effective tax rate for 2010 by 32 percentage points. |
| |
(b) | The impact of a goodwill impairment charge, which is not deductible for income tax purposes, decreased the effective tax rate for 2010 by 36 percentage points. |
2012 versus 2011
Ameren Corporation
Ameren's effective tax rate was higher in 2012 than 2011 primarily due to the impact of investment tax credit amortization, the reduction in the amortization of property-related regulatory assets and liabilities, and state income taxes on a large pretax book loss in 2012 compared with pretax income in 2011.
Variations in effective tax rates in Ameren's business segments and for the Ameren Companies between 2012 and 2011 were as follows:
Ameren Missouri
Ameren Missouri's effective tax rate was higher primarily because of an increase in reserves for uncertain tax positions in 2012, compared to a decrease in 2011. Additionally, the effective tax rate increased because of the decreased impact of the amortization of property-related regulatory assets and liabilities, and estimated tax credits on higher pretax income in 2012 compared with 2011.
Ameren Illinois
Ameren Illinois' effective tax rate was higher primarily because of the favorable impact of recording the adjustment to deferred tax assets due to the Illinois statutory income tax rate increase in 2011.
Merchant Generation
The Merchant Generation segment's effective tax rate was lower primarily because of the unfavorable impact of recording an adjustment to deferred tax liabilities in the prior year due to the Illinois statutory income tax rate increase in 2011, along with the decreased impact of the permanent book tax differences on a large pretax loss in 2012, which was partially offset by favorable changes in the reserves for uncertain tax positions in 2011.
2011 versus 2010
Ameren Corporation
Ameren's effective tax rate was lower in 2011 than in 2010, primarily because of the impact of the nondeductible goodwill impairment charge in 2010. See Note 17 - Impairment and Other Charges under Part II, Item 8, of this report for additional information on the goodwill impairment charges. In addition, there was a noncash, after-tax charge to earnings of $13 million, in the first quarter of 2010, to reduce deferred tax assets. The charge to earnings was recorded because of legislation enacted in the first quarter of 2010 that resulted in retiree health care costs no longer being deductible for tax purposes to the extent that an employer's postretirement health care plan receives federal subsidies to provide retiree prescription drug benefits equivalent to Medicare prescription drug benefits. This was offset, in part, by the impact of the increased Illinois statutory tax rate effective at the beginning of 2011, along with lower favorable net amortization of property-related regulatory assets and liabilities in 2011 compared with 2010, changes to reserves for uncertain tax positions, and the decreased impact of federal and state tax credits.
Variations in effective tax rates in Ameren's business segments and for the Ameren Companies between 2011 and 2010 were as follows:
Ameren Missouri
Ameren Missouri's effective tax rate was higher, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities in 2011 compared to 2010, offset, in part, by the effect of the change in the tax treatment of retiree health care costs in 2010 and changes to reserves for uncertain tax positions.
Ameren Illinois
Ameren Illinois' effective tax rate was comparable between years.
Merchant Generation
The effective tax rate was higher in the Merchant Generation segment, primarily because the impact of the nondeductible goodwill impairment charge in 2010, the increase in the Illinois statutory income tax rate in 2011 and the decrease in the effective tax rate from the effect of the change in the tax treatment of retiree health care costs in 2010, partially offset by decreased Internal Revenue Code Section 199 production activity deductions, lower benefits from state tax credits related to
capital investments, and favorable changes to reserves for uncertain tax positions in 2011, compared to unfavorable changes in 2010.
Income from Discontinued Operations, Net of Tax
Ameren Illinois
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and AER completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to AER. Ameren Illinois 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 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 - 2010 Corporate Reorganization under Part II, Item 8, of this report for additional information.
LIQUIDITY AND CAPITAL RESOURCES
The tariff-based gross margins of Ameren's rate-regulated utility operating companies continue to be aare the principal source of cash from operating activities for the Ameren and its rate-regulated subsidiaries.Companies. A diversified retail customer mix primarily of rate-regulated residential, commercial, and industrial classes and a commodity mix of natural gas and electric servicecustomers provide a reasonably predictable source of cash flows for Ameren, Ameren Missouri and Ameren Illinois. In addition to using cash flows from operating activities, Ameren, Ameren Missouri and Ameren Illinois use available cash, credit agreement borrowings, commercial paper issuances, money pool borrowings, or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. Ameren, Ameren Missouri and Ameren Illinois may reduce their credit agreement or short-term borrowings with cash from operations or, at their discretion, with long-term borrowings, or, in the case of Ameren Missouri and Ameren Illinois, with equity infusions from Ameren. Ameren, Ameren Missouri and Ameren Illinois 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 support overall system reliability, achieve IEIMA performance standards,environmental compliance, and other improvements. Ameren intends to finance those capital expenditures and
investments in its rate-regulated businesses with a blend of equity and debt so that it maintains a capital structure of approximatelyin a range around 50% to 55% equity, assuming constructive regulatory environments. Ameren, Ameren Missouri and Ameren Illinois plan to implement their long-term financing plans for debt, equity, or equity-linked securities to finance their operations appropriately, to fund scheduled debt maturities, and to maintain financial strength and flexibility.
Merchant Generation sells power primarily through market-
based contracts with wholesale and retail customers to generateThe use of operating cash flows.flows and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, as defined by current liabilities exceeding current assets, as was the case at December 31, 2013. The working capital deficit as of December 31, 2013, was primarily the result of current maturities of long-term debt. Ameren is currently evaluating refinancing options for these current maturities including, in part, through the issuance of long-term notes. In addition, Ameren had $368 million of commercial paper issuances outstanding as of December 31, 2013. With the 2012 Ameren announced that it had concluded that the Merchant Generation segment was no longer a core component of its future business strategy. Ameren determined that it intends to, and it is probable that it will, exit the Merchant Generation business segment before the end of the previously estimated useful lives of that business segment's long lived assets. In consideration of this determination,Credit Agreements, Ameren has begun planningaccess to reduce, and ultimately eliminate, the Merchant Generation segment's, including Genco's, reliance on Ameren's financial support and shared services support. While it remains a business$2.1 billion of Ameren, the Merchant Generation segment will seek to fund its operations internally and therefore will seek not to rely on financing from Ameren or external, third-party sources. The Merchant Generation segment will seek to defer or reduce capital and operating expenses, sell certain assets, and to take other actions as necessary to fund its operations internally while maintaining safe and reliable operations.
Under the provisionscredit capacity of its indenture, Genco may not borrow additional funds from external third-party sources if its interest coverage ratio is less than a specified minimum or if its leverage ratio is greater than a specified maximum. See Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional information on Genco's indenture provisions. Based on projections as ofwhich $1.7 billion was available at December 31, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco's indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control, and if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. In March 2012, Genco entered into a put option agreement with AERG for the potential sale of the Grand Tower, the Gibson City, and the Elgin energy centers in order to provide an additional source of liquidity, if needed in the future. See Note 14 - Related Party Transactions, under Part II, Item 8, of this report for additional information regarding the put option agreement and Ameren's guarantee of AERG's contingent obligations under the put option agreement. Should a financing need arise at Genco, its sources of liquidity include available cash on hand, a return of money pool advances, money pool borrowings at the discretion of Ameren, sale of an asset or multiple assets, or exercising the put option agreement with AERG. With existing power market conditions and cash flow requirements, it is more likely than not that Genco will sell one or more of its three natural gas fired energy centers before the put option agreement expires on March 28, 2014. Ameren and AERG do not expect to extend the put option agreement beyond March 28, 2014. Based on current projections, it is probable during 2013 that Genco will need mid-month liquidity from either asset sales or money pool borrowings to support working capital needs. However, borrowings from the money pool are subject to Ameren's control, and if a Genco
intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and
circumstances existing at that time. Based on projections as of December 31, 2012, Genco estimates these financing sources are adequate to support its operations in 2013.
The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 20122013, 20112012, and 20102011:
| |
| Net Cash Provided By Operating Activities | | Net Cash (Used In) Investing Activities | | Net Cash (Used In) Financing Activities | Net Cash Provided By Operating Activities | | Net Cash (Used In) Investing Activities | | Net Cash Provided by (Used In) Financing Activities |
| 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 |
Ameren(a) | $ | 1,690 |
| | $ | 1,878 |
| | $ | 1,823 |
| | $ | (1,310 | ) | | $ | (1,048 | ) | | $ | (1,096 | ) | | $ | (426 | ) | | $ | (1,120 | ) | | $ | (804 | ) | |
Ameren(a) – continuing operations | | $ | 1,636 |
| | $ | 1,404 |
| | $ | 1,499 |
| | $ | (1,440 | ) | | $ | (1,153 | ) | | $ | (949 | ) | | $ | (149 | ) | | $ | (426 | ) | | $ | (1,020 | ) |
Ameren(a) – discontinued operations | | 57 |
| | 286 |
| | 379 |
| | (283 | ) | | (157 | ) | | (99 | ) | | — |
| | — |
| | (100 | ) |
| Ameren Missouri | 1,004 |
| | 1,056 |
| | 969 |
| | (703 | ) | | (627 | ) | | (700 | ) | | (354 | ) | | (430 | ) | | (334 | ) | 1,143 |
| | 1,004 |
| | 1,056 |
| | (687 | ) | | (703 | ) | | (627 | ) | | (603 | ) | | (354 | ) | | (430 | ) |
| Ameren Illinois | 519 |
| | 504 |
| | 593 |
| | (437 | ) | | (296 | ) | | (247 | ) | | (103 | ) | | (509 | ) | | (330 | ) | 651 |
| | 519 |
| | 504 |
| | (695 | ) | | (437 | ) | | (296 | ) | | 45 |
| | (103 | ) | | (509 | ) |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Cash Flows from Operating Activities
20122013 versus 20112012
Ameren Corporation
Ameren’s cash from operating activities decreasedassociated with continuing operations increased in 20122013, compared with 20112012. The following items contributed to the decreaseincrease in Ameren’s cash from operating activities associated with continuing operations during 20122013, compared with 20112012:
The absence in 2013 of $138 million in premiums paid to debt holders in 2012 in connection with the repurchase of the tendered principal of multiple series of Ameren Missouri and Ameren Illinois senior secured notes.
A $115 million increase in the cash flows associated with Ameren Missouri’s under-recovered FAC costs. Recoveries outpaced deferrals in 2013 by $41 million, while deferrals and refunds outpaced recoveries in 2012 by $74 million.
Electric and natural gas margins, as discussed in Results of Operations, increased by $109 million, excluding impacts of the noncash IEIMA revenue requirement
reconciliation adjustment, the under-recovery of MEEIA lost revenues and the MoPSC's July 2013 order, which resulted in a FAC prudence charge. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for further information.
A $94 million increase due to changes in Ameren Missouri coal inventory levels. In 2013, coal inventory levels decreased by $62 million because of delivery disruptions due to flooding, while in 2012, coal inventory levels increased by $32 million primarily because additional tons were held in inventory when generation levels were lower than expected due to market conditions.
The absence in 2013 of $25 million in severance payments made in 2012 as a result of the voluntary separation offers extended to Ameren Missouri employees in the fourth quarter of 2011.
A $22 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on Ameren Missouri and Ameren Illinois senior secured notes.
The receipt of $16 million in 2013 for storm restoration assistance provided to nonaffiliated utilities in 2012 at Ameren Illinois.
A one-time $7.5 million contribution, in 2012, by Ameren Illinois to the Illinois Science and Energy Innovation Trust, as required by the IEIMA, which was not repeated in 2013.
The following items partially offset the increase in Ameren's cash from operating activities associated with continuing operations during 2013, compared with 2012:
A $106 million increase in income tax payments for continuing operations. As discussed below, income tax payments at Ameren Missouri increased $89 million while income tax refunds at Ameren Illinois increased $1 million. Considering both Ameren's continuing and discontinued operations, Ameren made immaterial federal income tax payments in 2013.
A $91 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.
A $27 million increase in payments for the 2013 scheduled nuclear refueling and maintenance outage at the Callaway energy center. There was no refueling and maintenance outage in 2012.
The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $19 million from the Circuit Court of Stoddard County's registry and the Circuit Court of Cole County's registry, net of payments into those registries, as a result of a Missouri Court of Appeals ruling upholding the MoPSC's January 2009 electric rate order.
A $13 million increase in property tax payments, primarily at Ameren Missouri, caused by the timing of payments.
A $12 million increase in major storm restoration costs.
An $11 million increase in labor costs primarily related to increased staffing levels associated with IEIMA at Ameren Illinois.
An $8 million increase in pension and postretirement benefit plan contributions primarily caused by an increase in funding requirements in 2013 compared with 2012, partially offset by an additional postretirement contribution in 2012 at Ameren Illinois. In addition to the Ameren Missouri and Ameren Illinois amounts discussed below, Ameren's nonregistrant subsidiaries increased their contributions to the pension and postretirement benefit plans by $19 million.
Ameren’s cash from operating activities associated with discontinued operations decreased in 2013, compared with 2012, primarily because of a $277 million decrease in electric margins, excluding impacts of noncash unrealized MTM activity. The decrease was partially offset by a $99 million increase in income tax refunds in 2013 due to a reduction in pretax book income partially offset by a reduction in accelerated depreciation deductions. Ameren’s discontinued operations entities received these income tax refunds through the tax allocation agreement with Ameren’s continuing operations entities.
Ameren Missouri
Ameren Missouri’s cash from operating activities increased in 2013, compared with 2012. The following items contributed to the increase in Ameren Missouri’s cash from operating activities during 2013, compared with 2012:
A $115 million increase in the cash flows associated with under-recovered FAC costs. Recoveries exceeded deferrals in 2013 by $41 million, while deferrals and refunds exceeded recoveries in 2012 by $74 million.
A $94 million increase due to changes in coal inventory levels. In 2013, coal inventory levels decreased by $62 million because of delivery disruptions due to flooding, while in 2012, coal inventory levels increased by $32 million primarily because additional tons were held in inventory when generation levels were lower than expected due to market conditions.
Electric and natural gas margins, as discussed in Results of Operations, increased by $91 million, excluding the impact of the noncash revenues associated with the under-recovery of MEEIA lost revenues and the charge recorded in 2013 associated with the FAC prudence review.
The absence in 2013 of $62 million in premiums paid to debt holders in 2012 in connection with the repurchase of the tendered principal of multiple series of senior secured notes.
The absence in 2013 of $25 million in severance payments made in 2012 as a result of the voluntary separation offers extended to employees in the fourth quarter of 2011.
An $8 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on senior secured notes.
The following items partially offset the increase in Ameren Missouri's cash from operating activities during 2013, compared with 2012:
Income tax payments totaled $86 million in 2013 resulting primarily from a reduction in accelerated depreciation deductions while income tax refunds were $3 million in 2012.
A $60 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.
A $27 million increase in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center. There was no refueling and maintenance outage in 2012.
A $20 million increase in property tax payments caused by the timing of payments.
The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $19 million from the Circuit Court of Stoddard County's registry and the Circuit Court of Cole County's registry, net of payments into those registries, as a result of a Missouri Court of Appeals ruling upholding the MoPSC's January 2009 electric rate order.
A $9 million increase in pension and postretirement benefit plan contributions primarily caused by an increase in funding requirements in 2013 compared with 2012.
An $8 million increase in major storm restoration costs.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased in 2013, compared with 2012. The following items contributed to the increase in Ameren Illinois’ cash from operating activities during 2013, compared with 2012:
The absence in 2013 of $76 million in premiums paid to debt holders in 2012 in connection with the repurchase of the tendered principal of multiple series of senior secured notes.
A $20 million decrease in pension and postretirement benefit plan contributions primarily caused by an additional postretirement contribution in 2012.
The receipt of $16 million in 2013 for storm restoration assistance provided to nonaffiliated utilities in 2012.
A $13 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on senior secured notes.
Electric and natural gas margins, as discussed in Results of Operations, increased by $11 million, excluding the impact from the noncash IEIMA revenue requirement reconciliation adjustment.
A one-time $7.5 million contribution, in 2012, to the Illinois Science and Energy Innovation Trust as required by the IEIMA.
A $7 million decrease in property tax payments due to two electricity distribution tax credit refunds received in 2013.
The following items partially offset the increase in Ameren Illinois' cash from operating activities during 2013, compared with 2012:
A $29 million increase in accounts receivable balances to reflect the timing of revenues earned but not yet collected from customers.
An $11 million increase in labor costs primarily related to increased staffing levels associated with IEIMA.
2012 versus 2011
Ameren Corporation
Ameren's cash from operating activities associated with continuing operations decreased in 2012, compared with 2011. The following items contributed to the decrease in cash from operating activities associated with continuing operations during 2012, compared with 2011:
Cash flows associated with Ameren Missouri's under-recovered FAC costs, which decreased by $161 million. Recoveries outpacedexceeded deferrals in 2011 by $87 million, while deferrals outpacedexceeded recoveries in 2012 by $74 million.
The premiums paid to debt holders in connection with the
repurchase of the tendered principal of multiple series of Ameren Missouri and Ameren Illinois senior secured notes, which premiums totaled $138 million. See Note 5 -– Long-term Debt and Equity Financings under Part II, Item 8, of this report for additionalfurther information.
A $105An $82 million decrease in cash collections from customer receivables, excluding the impacts of the receipt of funds from, and deposits into, court registries discussed separately below, primarily caused by milder weather in December 2011, compared with December 2010.
Income tax payments related to continuing operations of $1$10 million in 2012, compared with income tax refunds of $61$47 million in 2011. The 2011 refund resulted primarily from an IRS settlement, while the 2012 payment was caused by the purchase of state tax credits. Ameren did not make material federal income tax payments in either period because of accelerated deductions authorized by economic stimulus legislation and other deductions.
Electric and natural gas margins, as discussed in Results of Operations, which decreased by $29 million, excluding impacts of noncash MTM transactions and Ameren Illinois' noncash IEIMA formula ratemaking adjustment.
A net $22$40 million increase in coal inventory primarily caused by a $40 million increase at Ameren Missouri, discussed below offset by an $18 million decreaseprimarily because additional tons were held in Merchant Generationinventory when generation levels were lower than expected due to market conditions, the absence in 2012 of flooding that impeded coal inventory, primarily due to
continued focus on inventory reductions, partially offset bydeliveries in 2011, increased coal prices.prices, and milder weather conditions in early 2012.
A $22 million increase in energy efficiency expenditures, primarily for Ameren Illinois customer programs, which are recovered through customer billings over time.
The following items partially offset the decrease in Ameren’sAmeren's cash from operating activities associated with continuing operations during 2012,, compared with 2011:2011:
Electric and natural gas margins, as discussed in Results of Operations, which increased by $111 million, excluding Ameren Illinois' noncash IEIMA revenue requirement reconciliation adjustment.
Ameren Missouri's receipt of $37 million from the Stoddard County Circuit Court's registry and the Cole County Circuit Court's registry as the MoPSC's 2009 and 2010 electric rate orders were upheld on appeals. Additionally, $24 million fewer Ameren Missouri receivables were paid into the court registries in 2012 in connection with the electric rate order appeals. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
A $53$52 million decrease in pension and postretirement plan contributions. In 2011, Ameren Illinois contributed to Ameren's postretirement benefit plan trust an incremental $100 million in excess of Ameren Illinois' annual postretirement net periodic cost for regulatory purposes.
A $50 million decrease in the cost of natural gas held in storage because of lower prices.
A $35 million decrease in major storm restoration costs.
A $25$26 million decrease in taxes other than income tax payments, primarily related to Ameren Missouri, caused by the timing of property tax payments at each year end, partially offset by higher assessed property tax values.
A $21 million reduction in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, caused by the absence of a refueling
outage in 2012.
A $21 million increase in natural gas commodity over-recovered costs under the PGA,PGAs, primarily related to Ameren Illinois.
A $20 million decrease in payments related to the MISO liability due, in part, to fewer payments required for December 2011 purchases compared to the payments required for December 2010 purchases.
A $20 million decrease in interest payments, primarily due
to the Ameren Illinois senior secured note redemption in June 2011 and a $7 million interest reduction associated with Ameren's borrowings under its credit facility agreements and issuances under its commercial paper program as fewer borrowings and issuances were made in 2012.
A net $19$5 million decrease in collateral posted with counterparties for the reasons discussed at the registrant subsidiaries below and a decreasedue, in collateral returned by nonregistrant subsidiaries of $5 million duepart, to changes in the market prices of power and natural gas and coal and in contracted commodity volumes.
The receiptCash from operating activities associated with discontinued operations decreased in 2012, compared with 2011, primarily because of $16a $140 million for netdecrease in electric margins, excluding impacts of noncash unrealized MTM activity, partially offset by an $18 million decrease in coal transfersinventory, primarily due to refiners under agreements, primarily for the Merchant Generation segment, that began in late 2011. Thecontinued focus on inventory reductions, partially offset by increased coal will be purchased back from the refiners in a subsequent period.prices.
Ameren Missouri
Ameren Missouri’s cash from operating activities decreased in 2012 compared with 2011.2011. The following items contributed to the decrease in cash from operating activities during 2012,, compared with 2011:2011:
Cash flows associated with Ameren Missouri's under-recovered FAC costs, which decreased by $161 million. Recoveries outpacedexceeded deferrals in 2011 by $87 million, while deferrals outpacedexceeded recoveries in 2012 by $74 million.
The premiums paid to debt holders for the repurchase of the tendered principal of multiple series of tendered senior secured notes, which premiums totaled $62 million.
A $40 million increase in coal inventory primarily due tobecause additional tons were held in inventory becausewhen generation levels were belowlower than expected levels due to market conditions, the absence in 2012 of flooding that impeded coal deliveries in 2011, increased coal prices, and milder weather conditions in early 2012.
A $25 million decrease in cash collections from customer receivables, excluding the receipt of funds from, and deposits into, court registries discussed separately below, primarily caused by milder weather in December 2011, compared with December 2010.
A net $6 million increase in collateral posted with counterparties due, in part, to changes in the market price of power and gas and in contracted commodity volumes.
The following items partially offset the decrease in Ameren Missouri’s cash from operating activities during 2012,, compared with 2011:2011:
Electric and natural gas margins, as discussed in Results of Operations, which increased by $83 million.
$83 million.Receipt of $37 million from the Stoddard County Circuit Court's registry and the Cole County Circuit Court's registry as the MoPSC's 2009 and 2010 electric rate
orders were upheld on appeals. Additionally, $24 million fewer Ameren Missouri receivables were paid into the court registries in 2012 in connection with the electric rate
order appeals. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
A $28 million decrease in property tax payments caused by the timing of property tax payments at each year end, partially offset by higher assessed property tax values.
A $21 million reduction in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, caused by the absence of acenter. There was no refueling and maintenance outage in 2012.
A $20 million decrease in major storm restoration costs.
A $15 million reduction in energy efficiency expenditures.
Income tax refunds of $3$3 million in 2012, compared with income tax payments of $9$9 million in 2011. Ameren Missouri’s 2011 tax liability was reduced by accelerated deductions authorized by economic stimulus legislation, use of its net operating loss carryforwards, and other deductions. Ameren Missouri's 2012 tax refund is primarily due to a tax deduction related to the repurchase of debt, partially offset by an increase in income from the resolution of the 2009 and 2010 electric rate order appeals discussed above
above.An $11 million reduction in labor costs due to staff reductions.
Ameren Illinois
Ameren Illinois’ cash from operating activities increased in 2012 compared with 2011.2011. The following items contributed to the increase in Ameren Illinois' cash from operating activities during 2012,, compared with 2011:2011:
A $65$65 million decrease in pension and postretirement benefit plan contributions. In 2011, Ameren Illinois contributed to Ameren's postretirement benefit plan trust an incremental $100 million in excess of Ameren Illinois' annual postretirement net periodic cost for regulatory purposes.
A $46 million decrease in the cost of natural gas held in storage because of lower prices.
Electric and natural gas margins, as discussed in Results of Operations, that increased by $26$26 million,, excluding impacts of the noncash IEIMA formula ratemakingrevenue requirement reconciliation adjustment.
A net $20$20 million decrease in collateral posted with counterparties due, in part, to changes in the market price of natural gas and in contracted commodity volumes.
A $20 million decrease in payments related to the MISO liability due, in part, to fewer payments required for December 2011 purchases compared with payments required for December 2010 purchases.
A $16 million increase in natural gas commodity over-recovered costs under the PGA.
A $15 million decrease in major storm restoration costs.
A $12$12 million decrease in interest payments, primarily due to the redemption of senior secured notes in June 2011.
An $8 million increase in income tax refunds primarily due to lower pretax book income along with a tax deduction
related to the repurchase of debt.
The following items partially offset the increase in Ameren IllinoisIllinois' cash from operating activities during 2012,, compared with 2011:2011:
The premiums paid to debt holders for the repurchase of the tendered principal of multiple series of tendered senior secured notes, which premiums totaled $76 million.
A $68 million decrease in cash collections from customer receivables, primarily caused by milder weather in December 2011, compared with December 2010.
A $37 million increase in energy efficiency expenditures for customer programs that are recovered through customer billings over time.
A $26 million increase in payments to contractors for additional reliability, maintenance, and IEIMA projects.
A $12 million increase in labor costs, primarily because of staff additions due to the requirements of the IEIMA.
A one-time $7.5 million payment to the Illinois Science and Energy Innovation Trust, as required by the IEIMA.
2011 versus 2010
Ameren Corporation
Ameren’s cash from operating activities increased in 2011, compared with 2010. The following items contributed to the increase in cash from operating activities during 2011, compared with 2010:
Ameren Missouri’s regulatory asset for FAC under-recovery, which decreased by $216 million as more deferred costs were recovered from customers during 2011.
Trade accounts receivablePension and unbilled revenues balances decreased, primarily because of milder weather in the fourth quarter of 2011, compared with the fourth quarter of 2010. Those same weather conditions caused accounts payable balances to MISO and natural gas suppliers to decrease as less power and natural gas was purchased. Additionally, during 2011, MISO shortened the length of its settlement terms for all of its members. The new terms resulted in an acceleration of payments that previously would not have been made until 2012. These factors resulted in a net increase of $120 million in cash from operating activities in 2011 compared with 2010.
A net $100 million decrease in collateral posted with counterparties for the reasons discussed at the registrant subsidiaries below, partially offset by a decrease in collateral returned from Ameren counterparties of $10 million and additional collateral posted to counterparties of $4 million due to changes in the market price of power.
Deferred budget billing receivables that decreased by $71 million, partially as a result of milder weather.
A $45 million decrease in interest payments, primarily due to the long-term debt redemptions at the registrant subsidiaries discussed below and a reduction in Ameren’s borrowings under its credit facility agreements, which resulted in an $11 million reduction in interest payments.
An $11 million reduction in payments for scheduled
nuclear refueling and maintenance outages at the Callaway energy center caused primarily by the timing of the 2011 outage compared with the 2010 outage, which had unpaid liabilities as of December 31, 2011.
The following items reduced the increase in Ameren’s cash from operating activities during 2011, compared with 2010:
A $115 million increase in pension and postretirement benefit plan contributions. Ameren Illinois contributed to Ameren’s postretirement benefit VEBA trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes.
Electric and natural gas margins, as discussed in Results of Operations, which decreased by $86 million, excluding impacts of noncash MTM transactions.
During 2010, Ameren’s Merchant Generation coal-fired energy centers significantly reduced their coal inventory levels, which resulted in an estimated $64 million cash savings in excess of the smaller inventory reduction that occurred in 2011.
A $55 million decrease associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011.
A $34 million increase in major storm restoration costs.
A $31 million decrease in income tax refunds. The 2010 refund resulted primarily from a 2009 change in tax treatment of electric generation plant expenditures. The 2011 refund resulted primarily from casualty loss deductions due to an Internal Revenue Service audit settlement. Ameren did not make any federal income tax payments in 2011 because of accelerated deductions authorized by economic stimulus legislation, use of its net operating loss carryforwards, and other deductions.
A $30 million increase in taxes other than income tax payments that related to higher assessed property tax values for energy center enhancements, county property tax rate increases, and the timing of property tax payments at each year end for Ameren Missouri. Ameren Illinois incurred an increase in electricity distribution and invested capital tax payments resulting from the tiered rate structure for the merged entity.
Reduced collections as more utility customers were past due on their bills on December 31, 2011, than on December 31, 2010. Additionally, write-offs of customer receivable balances increased because of economic conditions.
An $18 million increase in Ameren Missouri receivables held in court registries under the appeals of the MoPSC’s 2009 and 2010 rate orders. See Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report for additional information.
A $16 million decrease in Ameren Illinois’ electric purchased power commodity over-recovered costs.
A $15 million increase in energy efficiency expenditures for new customer programs. The Ameren Illinois amount is recovered through customer billings over time.
An $11 million decrease in natural gas commodity over-recovered costs under the PGA, primarily in Illinois.
A $7 million increase in preliminary study expenditures, primarily at Ameren Missouri for environmental compliance testing.
Ameren Missouri
Ameren Missouri’s cash from operating activities increased in 2011 compared with 2010. The following items contributed to the increase in cash from operating activities during 2011, compared with 2010:
The regulatory asset for FAC under-recovery, which decreased by $216 million as more deferred costs were recovered from customers during 2011.
Trade accounts receivable and unbilled revenue balances, which decreased by $65 million, primarily because of milder weather in the fourth quarter of 2011, compared with the fourth quarter of 2010.
Deferred budget billing receivables, which decreased by $33 million, partially as a result of milder weather.
Electric and natural gas margins, as discussed in Results of Operations, which increased by $25 million, excluding impacts of noncash MTM transactions.
A $16 million decrease in payments associated with major outages at coal-fired energy centers, primarily because the scope of the major outages in 2011 was not as extensive in 2010.
An $11 million reduction in payments due to the timing of scheduled nuclear refueling and maintenance outages at the Callaway energy center as discussed above.
A $4 million decrease in interest payments, primarily due to the redemption of subordinated deferrable interest debentures in September 2010.
The following items reduced the increase in Ameren Missouri’s cash from operating activities during 2011, compared with 2010:
Income tax payments of $9 million in 2011, compared with income tax refunds of $106 million in 2010. The 2010 refund resulted primarily from a 2009 change in tax treatment of electric generation plant expenditures and accelerated deductions authorized by economic stimulus legislation. Ameren Missouri’s 2011 tax liability was reduced by accelerated deductions authorized by economic stimulus legislation, use of its net operating loss carryforwards, and other deductions.
A $55 million decrease associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011.
A $23 million increase in property tax payments caused primarily by higher assessed tax values for energy center enhancements, county tax rate increases, and the timing of property tax payments at each year end.
A $21 million increase in major storm restoration costs.
An $18 million increase in receivables held in court registries under the appeals of the MoPSC’s 2009 and
2010 rate orders.
Reduced collections as more customers were past due on their bills on December 31, 2011, than on December 31, 2010. Additionally, write-offs of customer receivable balances increased because of economic conditions.
A net $6 million decrease in collateral returned from exchange counterparties and, to a lesser extent, additional collateral postings to MISO, all due to changes in the market price of power and natural gas.
A $6 million increase in preliminary study expenditures, primarily for environmental compliance testing.
A $6 million increase in energy efficiency expenditures for new customer programs.
Ameren Illinois
Ameren Illinois’ cash from operating activities decreased in 2011 compared with 2010. Ameren Illinois’ cash from operating activities included AERG’s operating cash flows for all periods prior to October 1, 2010, which were presented as discontinued operations in Ameren Illinois’ consolidated statement of cash flows. Excluding the impacts of discontinued operations, Ameren Illinois’ cash from operating activities decreased in 2011 compared with 2010. The following items contributed to the decrease in cash from operating activities associated with continuing operations during 2011, compared with 2010:
A $103 million increase in pension and postretirement benefit plan contributions. Ameren Illinois contributed to Ameren’s postretirement benefit VEBA trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes.
A $38 million decrease in income tax refunds caused primarily by a reduction in transmission and distribution repair deductions, partially offset by additional casualty loss deductions from an Internal Revenue Service audit settlement. Ameren Illinois did not make any federal income tax payments in 2011 because of accelerated deductions authorized by economic stimulus legislation and other deductions.
Electric and natural gas margins, as discussed in Results of Operations, which decreased by $30 million, excluding impacts of noncash MTM transactions.
A $16 million decrease in electric purchased power commodity over-recovered costs.
A $13 million increase in major storm restoration costs.
Reduced collection results as more customers were past due on their bills on December 31, 2011, than on December 31, 2010. Additionally, write-offs of customer receivable balances increased because of economic conditions.
A $9 million increase in taxes other than income payments, due primarily to an increase in electricity distribution and invested capital tax payments resulting from the tiered rate structure for the merged entity.
A $9 million decrease in natural gas commodity over-recovered costs under the PGA.
A $9 million increase in energy efficiency expenditures for new customer programs. These expenditures are recovered through customer billings over time.
The following items reduced the decrease in Ameren Illinois’ cash from operating activities associated with continuing operations during 2011, compared with 2010:
A net $120 million decrease in collateral posted with counterparties due, in part, to a reduction in the market price of natural gas and in contracted volumes.
Trade accounts receivable and unbilled revenues balances decreased, primarily because of milder weather in the fourth quarter of 2011, compared with the fourth quarter of 2010. Those same weather conditions caused accounts payable balances to MISO and natural gas suppliers to decrease as less power and natural gas was purchased. Additionally, during 2011, MISO shortened the length of its settlement terms for all of its members. The new terms resulted in an acceleration of payments that previously would not have been made until 2012. These factors resulted in a net increase of $63 million in cash from operating activities in 2011 compared with 2010.
Deferred budget billing balances decreased by $38 million, partially as a result of milder weather.
An $11 million decrease in interest payments, primarily due to the redemption of first mortgage bonds in September 2010.
Pension FundingPostretirement Plans
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, 20122013, its investment performance in 20122013, and its pension funding policy, Ameren expects to make annual contributions of $6020 million to $150100 million in each of the next five years, with aggregate estimated contributions of $550270 million. We expect Ameren Missouri’s and Ameren Illinois’ portion of the future funding requirements to be 50%52% and 40%47%, respectively. These amounts are estimates. The estimates 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 2012,2013, Ameren contributed $134156 million to its pension plans. See Note 11 -– Retirement Benefits under Part II, Item 8, of this report for additional information.
On December 2, 2013, Ameren completed the divestiture of New AER to IPH. In accordance with the transaction agreement, Ameren retained the pension obligations as of December 2, 2013, associated with the current and former employees of New AER and its subsidiaries who were included in the Ameren Retirement Plan and the Ameren Supplemental Retirement Plan. Ameren also retained the postretirement benefit obligations associated with the employees of New AER and its subsidiaries who were eligible to retire at December 2, 2013, from the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan. IPH assumed the existing pension and other postretirement benefit obligations associated with EEI's current and former employees that are included in EEI’s single-employer pension and other postretirement plans. Coincident with Ameren’s divestiture of New AER, a significant number of employees left Ameren which required a
measurement of Ameren’s pension and postretirement benefit plan assets and obligations as of December 2, 2013, based upon current market conditions. The reduction in obligations for the postretirement benefit plans and the accelerated recognition of gains previously recorded in accumulated other comprehensive income that had not previously been recognized through net periodic benefit cost for the pension and postretirement benefit plans resulted in a $19 million pretax curtailment gain, which was included in discontinued operations.
Ameren completed another measurement as of December 31, 2013, as is its historical accounting practice, based upon the market conditions at the end of the year. Excluding the EEI plans, which were assumed by IPH during 2013, Ameren’s unfunded obligation under its pension and other postretirement benefit plans was $461 million and $1,143 million as of December 31, 2013, and December 31, 2012, respectively. The primary factors contributing to this unfunded obligation reduction during 2013 were a 75 basis point increase in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligations, and asset returns being better than expected. The offset to the unfunded obligation reduction was primarily a reduction to regulatory assets.
Cash Flows from Investing Activities
20122013 versus 20112012
Ameren's cash used in investing activities associated with continuing operations increased by $262$287 million during 2013, compared with 2012. Capital expenditures increased $316 million, primarily because of increased expenditures for transmission in Illinois, reliability projects, and storm restoration costs. The increase in cash flows used in investing activities was partially offset by a $46 million decrease in nuclear fuel expenditures due to timing of purchases.
Cash used in investing activities associated with Ameren’s discontinued operations increased $126 million during 2013, compared with 2012, primarily due to the requirement to leave cash of $235 million with New AER upon divestiture, pursuant to the transaction agreement with IPH. This use of cash was partially offset by reduced capital expenditures in 2013 as a result of the deceleration of the scrubber construction project at the Newton energy center.
Ameren Missouri's cash used in investing activities decreased $16 million during 2013, compared with 2012, primarily due to changes in money pool advances and a $46 million decrease in nuclear fuel expenditures due to timing of purchases. The decrease in cash used in investing activities was partially offset by increased capital expenditures and the absence in 2013 of a 2012 receipt of $18 million for federal tax grants related to renewable energy construction projects. Capital expenditures increased $53 million, primarily because of increased expenditures for reliability projects and an increase in storm restoration costs.
Ameren Illinois' cash used in investing activities increased $258 million during 2013, compared with 2012. Capital expenditures increased $259 million, primarily due to increased expenditures of $164 million for transmission and reliability projects, $18 million for storm restoration costs, and $12 million for IEIMA projects.
2012 versus 2011
Ameren's cash used in investing activities associated with continuing operations increased by $204 million during 2012, compared with 2011. Capital expenditures increased $210$182 million primarily because of increased expenditures for maintenancereliability, boiler, and reliability, boiler,
turbine and scrubber projects, which more than offset a decrease in storm restoration costs. Cash flows used in investing activities also increased because of a $29$29 million increase in nuclear fuel expenditures due to timing of purchases. In 2012, cash flows from investing activities benefited from property sale proceeds, principally attributable to $16purchases, which was partially offset by a receipt of $18 million in proceeds received from the sale of Medina Valley energy center's net property and plant, and $18 million federal tax grants related to renewable energy construction projects. In 2011, cash flows from
Cash used in investing activities benefited from property saleassociated with discontinued operations increased $58 million during 2012, compared with 2011. Capital expenditures increased $26 million as a result of increased expenditures related to the scrubber project at the Newton energy center, which more than offset a reduction in maintenance and upgrade project expenditures due to the timing of energy center outages. In 2012, proceeds principally attributable to $45of $16 million of proceedswere received from the sale of Genco's interest in its Columbia CTthe Medina Valley energy center, as well as $8center’s net property and plant. In 2011, Genco received $45 million inof proceeds from the sale of its investmentinterest in a leveraged lease and a $9 million payment received from an Ameren Missouri settlement with the DOE related to nuclear waste disposal.Columbia CT energy center.
Ameren Missouri's cash used in investing activities increased $76$76 million during 2012, compared with 2011. Capital expenditures increased $45$45 million primarily because of increased expenditures for maintenance and reliability, boiler, and turbine projects, which more than offset a $29 million decrease in storm restoration costs. Cash flows used in investing activities also increased due to a $29$29 million increase in nuclear fuel expenditures due to timing of purchases for the spring 2013 reload. In 2012, cash flows from investing activities benefited from $18 million of federal tax grants received related to renewable energy construction projects. In 2011, cash flows used in investing activities benefited from a $9 million payment receivedreceipt from a settlement with the DOE related to nuclear waste disposal.
Ameren Illinois' cash used in investing activities increased $141$141 million during 2012, compared with 2011. Capital expenditures increased $91$91 million as a result of increased expenditures for maintenance and reliability capital projects, including $27 million for IEIMA projects, which more than offset a $16 million decrease in storm restoration costs. In 2011, cash flows from investing activities benefited from repayments of advances previously paid to ATXI as a result of the completion of a project under a joint ownership agreement.
2011 versus 2010
Ameren’s cash used in investing activities decreased by $48 million during 2011, compared with 2010. In 2011, cash flows from investing activities benefited from an increase of proceeds from property sales as well as $8 million in proceeds from the sale of its investment in a leveraged lease and a $9 million payment received from the DOE under the terms of an Ameren Missouri settlement with the DOE in 2011 related to nuclear waste disposal. Net cash used for capital expenditures decreased $12 million during 2011, compared with 2010. Reductions in capital expenditures caused by the completion of two energy center scrubber projects in 2010 were offset, in part, by an increase in storm-related repair costs, an increase in electric transmission investments, and expenditures for a third energy center scrubber project in 2011.
Ameren Missouri’s cash used in investing activities decreased by $73 million during 2011, compared with 2010, principally because of a $74 million decrease in capital expenditures and a $9 million payment received from the DOE in 2011 under the terms of the settlement with the DOE related to nuclear waste disposal. These cash benefits were reduced by a $6 million net decrease in nuclear decommissioning trust fund activities. Capital expenditures were lower in 2011 as a result of the completion in 2010 of two scrubbers at Ameren Missouri’s Sioux energy center and boiler projects, which offset a $28 million increase in capital expenditures related to storm-related repair costs.
Ameren Illinois’ cash used in investing activities increased by $49 million during 2011, compared with 2010. There was a $70 million increase in capital expenditures, primarily as a result of increased investment in electric transmission assets and a $17 million increase in capital expenditures related to storm-related repair costs. In 2011, cash flows from investing activities benefited from the repayments of advances previously paid to ATXI, as a result of the completion of a project under a joint ownership agreement. In 2010, cash flows from investing activities benefited from the proceeds received on an intercompany note receivable, offset, in part, by advances to ATXI.
Capital Expenditures
The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2013, 2012, 2011, and 2010:2011:
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
Ameren(a) | $ | 1,379 |
| | $ | 1,063 |
| | $ | 881 |
|
| Ameren Missouri | 648 |
| | 595 |
| | 550 |
|
| Ameren Illinois | 701 |
| | 442 |
| | 351 |
|
|
| | | | | | | | | | | |
| | 2012 | | 2011 | | 2010 |
Ameren(a) | $ | 1,240 |
| | $ | 1,030 |
| | $ | 1,042 |
|
| Ameren Missouri | 595 |
| | 550 |
| | 624 |
|
| Ameren Illinois | 442 |
| | 351 |
| | 281 |
|
| Merchant Generation | 178 |
| | 153 |
| | 101 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and the elimination of intercompany transfers. |
Ameren’s 20122013 capital expenditures principally consisted of the following expenditures at its subsidiaries. Ameren Missouri spent $53 million on Labadie precipitator upgrades, $30 million on storm restoration, and $29 million on the replacement of the Callaway nuclear reactor head scheduled to be replaced during the 2013 Callaway2014 refueling and maintenance outageoutage. Ameren Illinois spent $269 million on transmission initiatives, $39 million on IEIMA projects, and $23 million on a boiler upgrade project. Ameren Illinoisstorm restoration. ATXI spent $27$51 million on IEIMA-related expenditures. Merchant Generation spent $141 million as part of the construction of two scrubbers at the Newton energy center to comply with environmental regulations.Illinois Rivers project. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois, as well as to fund various Ameren Missouri energy center upgrades.
Ameren’s 20112012 capital expenditures principally consisted of the following expenditures at its subsidiaries. Ameren Missouri spent $24$30 million on building its Maryland Heights energy centerthe replacement of the Callaway nuclear reactor head, scheduled to be replaced during the 2014 refueling and $31maintenance outage and $23 million for storm-related repair costs.on a boiler upgrade project. Ameren Illinois incurred storm-related repair costs of $20 million. Merchant
Generation spent $75$27 million toward scrubbers at the Newton and Coffeen energy centers to comply with environmental regulations.on IEIMA projects. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois, as well as to fund various Ameren Missouri energy center upgrades.
Ameren’s 20102011 capital expenditures principally consisted of the following expenditures at its subsidiaries. Ameren Missouri spent $130$24 million toward two scrubbers aton building its SiouxMaryland Heights energy center which were completed in 2010. At Merchant Generation, there was a cash outlayand $31 million on storm-related repair costs. Ameren Illinois incurred storm-related repair costs of $29 million for energy center scrubber projects. The scrubbers are necessary to comply with environmental regulations.$20 million. Other capital expenditures were made principally to maintain, upgrade, and expand the reliability of the transmission and distribution systems of Ameren Missouri and Ameren Illinois, as well as to fund various Ameren Missouri energy center upgrades.
The following table estimatespresents Ameren's estimated capital expenditures that will be incurred from 20132014 through 2017,2018, including construction expenditures, capitalized interest for the Merchant Generation business, allowance for funds used during construction for Ameren's rate-regulated utility businesses, and estimated expenditures for compliance with known and existing environmental regulations. The table below includes AER's estimatedAmeren expects to allocate more of its discretionary capital expenditures for the installation of the two scrubbers at the Newton energy center, which are estimated to be installed by the end of 2019. See OutlookAmeren Illinois and also Note 15 - Commitments and Contingencies under Part II, Item 8, of this report for further discussion of the impact of declining power pricesATXI based on the Merchant Generation segment and the Newton energy center construction milestones. The table below assumes that Ameren continues to own the AER energy centers through 2017. See also Note 17 - Impairment and Other Charges under Part II, Item 8, of this report for further discussion on Ameren's plan to exit the Merchant Generation business.their regulatory frameworks.
| | | | 2013 | | 2014 - 2017 | | Total | 2014 | | 2015 - 2018 | | Total |
| Ameren Missouri | $ | 720 |
| | $ | 2,250 |
| - | $ | 3,045 |
| | $ | 2,970 |
| - | $ | 3,765 |
| $ | 760 |
| | $ | 2,495 |
| - | $ | 2,740 |
| | $ | 3,255 |
| - | $ | 3,500 |
|
| Ameren Illinois | 695 |
| | 2,400 |
| - | 3,250 |
| | 3,095 |
| - | 3,945 |
| 800 |
| | 2,600 |
| - | 2,860 |
| | 3,400 |
| - | 3,660 |
|
| AER | 70 |
| | 230 |
| - | 315 |
| | 300 |
| - | 385 |
| |
| ATXI | 60 |
| | 965 |
| - | 1,310 |
| | 1,025 |
| - | 1,370 |
| 240 |
| | 1,110 |
| - | 1,200 |
| | 1,350 |
| - | 1,440 |
|
Other(a) | (5 | ) | | 60 |
| - | 80 |
| | 55 |
| - | 75 |
| 25 |
| | 70 |
| - | 75 |
| | 95 |
| - | 100 |
|
| Ameren | $ | 1,540 |
| | $ | 5,905 |
| - | $ | 8,000 |
| | $ | 7,445 |
| - | $ | 9,540 |
| $ | 1,825 |
| | $ | 6,275 |
| - | $ | 6,875 |
| | $ | 8,100 |
| - | $ | 8,700 |
|
| |
| (a) | Includes the elimination of intercompany transfers. |
Ameren Missouri’s estimated capital expenditures include transmission, distribution, and generation-related investments, as well as expenditures for compliance with the environmental regulations discussed below.regulations. Ameren Illinois’ estimated capital expenditures are primarily for electric and natural gas transmission and distribution-related investments, and estimated capital expenditures incremental to historical average electric delivery capital expenditures to modernize its distribution system pursuant to the IEIMA. Until the uncertainty surrounding how the IEIMA will ultimately be implemented is removed, Ameren Illinois is slowing its IEIMA capital spending. Even though it is proceeding on a slower schedule, Ameren Illinois intends to meet
its IEIMA capital spending requirements. For additional information on the IEIMA, see Note 2 - Rate and Regulatory Matters under Part II, Item 8, of this report. AER's estimated capital expenditures are primarily for compliance with environmental regulations. Estimated capital expenditures for ATXI include the three MISO-approved multi-value transmission projects. For additional information regarding the IEIMA capital expenditure requirements and ATXI's transmission projects, see Business under Part I, Item 1, of this report.
We continually review ourAmeren Missouri's generation portfolio and expected power needs. As a result, weAmeren Missouri could modify ourits plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, such as the December 2012 Ameren announcement to exit the Merchant Generation business before the end of the previously estimated useful lives of its long-lived assets, the type of generation asset technology that will be employed, and whether capacity or power may be purchased, among other things. Additionally, we continually review the reliability of our transmission and distribution systems, expected capacity needs, and opportunities for transmission investments. The timing and amount of investments could vary because of changes in expected capacity, the condition of transmission and distribution systems, and our ability and willingness to pursue transmission investments, among other things. Any changes in future generation, transmission, or distribution needs could result in significant capital expenditures or losses being incurred, which could be material.
Environmental Capital Expenditures
Ameren Ameren Missouri and Merchant Generation will incur significant costs in future years to comply with existing and known federal and state regulations including those requiring the reduction of SO2, NOx, and mercury emissions from its coal-fired energy centers.
See Note 15 -– Commitments and Contingencies under Part II, Item 8, of this report for a discussion of existing environmental laws and regulations that affect, or may affect, our facilities and capital costs to comply with such laws and regulations, as well as our assessment of the potential impacts of the EPA’s proposed regulation of CCR and the finalized MATS, as of December 31, 2012.regulations.
Cash Flows from Financing Activities
2013 versus 2012
In 2013, we reduced our cost of borrowings through the repayment and redemption of long-term indebtedness, which had higher interest rates than the commercial paper and senior secured debt issued to finance such repayments and redemptions. During 2013, issuances under the Ameren and Ameren Missouri commercial paper programs were available at a lower interest rate than the interest rate available under the 2012 Credit Agreements.
Ameren’s net cash used in financing activities associated with continuing operations decreased during 2013 compared with 2012. In 2013, Ameren's cash flow from operating activities of $1.6 billion exceeded its capital expenditures of $1.4 billion, while in 2012 Ameren's cash flow from operating activities of $1.4
billion exceeded its capital expenditures of $1.1 billion. During 2013, Ameren used cash flow from operating activities, other available cash on hand, and commercial paper issuances, in part, to pay common stock dividends of $388 million, redeem $244 million of long-term Ameren Missouri indebtedness, and fund the $235 million cash requirement at divested New AER upon divestiture on December 2, 2013, pursuant to the transaction agreement with IPH. In addition, Ameren Illinois issued $280 million in senior secured debt and used the net proceeds of $276 million to repay at maturity $150 million of long-term indebtedness. In comparison, in 2012, Ameren subsidiaries issued $885 million in senior debt and used the proceeds, together with other available cash, to redeem or repay existing long-term indebtedness of $754 million and pay related premiums. Additionally, in 2012, Ameren repaid $148 million of its net short-term debt.
During 2013, no financing cash flows were utilized to meet the working capital and investing requirements of our discontinued operations.
Ameren Missouri’s net cash used in financing activities increased during 2013, compared with 2012. Ameren Missouri used cash on hand, net money pool receipts, and the excess cash from operating activities after capital expenditures, to redeem or repay existing long-term indebtedness of $244 million and pay common stock dividends of $460 million. In comparison, in 2012, Ameren Missouri issued $485 million of 3.90% senior secured notes and used the proceeds, together with other available cash, to redeem or repay existing long-term indebtedness of $422 million and to pay related premiums.
Ameren Illinois' financing activities provided net cash of $45 million in 2013 compared with 2012, when financing activities used net cash of $103 million. During 2013, Ameren Illinois issued $280 million in senior secured debt and used the net proceeds of $276 million to repay at maturity $150 million of long-term indebtedness, and pay common stock dividends of $110 million. During 2012, Ameren Illinois issued $400 million of 2.70% senior secured notes and used the proceeds, together with other available cash, to redeem or repay existing long-term indebtedness of $332 million and to pay related premiums. Ameren Illinois paid common stock dividends of $189 million in 2012.
2012 versus 2011
During 2012, we replaced and extended the expiration of our credit agreements. We reduced our reliance on short-term debt while maintaining adequate cash balances for working capital needs.
Ameren's net cash used in financing activities associated with continuing operations decreased during 2012, compared with 2011. Repayments of net short-term debt and credit agreement borrowings decreased by $433$333 million in 2012 compared with 2011. The decrease in cash provided by operating activities in 2012, combined with the increase in capital expenditures, resulted in less cash available to fund financing activities. However, Ameren was still able to repay all outstanding
short-term debt that existed at the beginningend of the year in 2012.2011. In 2012, Ameren subsidiaries issued $885 million in senior debt and used the proceeds, together with other available cash, to repurchase, redeem andor repay existing long-term indebtedness of $754 million and to pay related premiums. In 2011, Ameren Illinois funded the $150 million maturity of its senior secured notes with cash on hand and operating cash flows. There was also a reduction in refunds of advances previously received from generators of $73 million due to project completion in 2011. In 2011, common stock issued for DRPlus and the 401(k) plan increased cash flows from financing activities by $65 million. In 2012, Ameren shares were purchased in the open market for DRPlus and the 401(k) plan, resulting in noncash financing activity of $7 million due to the timing of DRPlus common stock dividend funding.
During 2012, no financing cash flows were utilized to meet working capital and investing requirements associated with discontinued operations. In 2011, $100 million of short-term borrowing obligations were repaid using surplus net cash from operating activities.
Ameren Missouri's net cash used in financing activities decreased during 2012, compared with 2011. In September 2012, Ameren Missouri issued $485 million of 3.90% senior secured notes and used the proceeds, together with other available cash, to repurchase andredeem or repay existing long-term indebtedness of $422 million and to pay related premiums. In 2011, refunds of advances previously received from generators
decreased cash flows from financing activities by $19 million as a result of project completion.
Ameren Illinois' net cash used in financing activities decreased during 2012, compared with 2011. In August 2012, Ameren Illinois issued $400 million of 2.70% senior secured notes and used the proceeds, together with other available cash, to repurchase and redeem or repay existing long-term indebtedness of $332 million and pay related premiums. In 2011, Ameren Illinois funded the $150 million maturity of its senior secured notes utilizingby using cash on hand and operating cash flows. In 2012, Ameren Illinois common stock dividends decreased by $138 million.million relative to 2011 dividends. Additionally, there was a reduction in 2012 in refunds of advances previously received from generators of $53 million due to project completion in 2011.
2011 versus 2010
During 2011, we reduced our reliance on borrowings from short-term debt and credit agreements, and we reduced long-term debt outstanding while maintaining adequate cash balances for working capital needs.
Ameren’s cash used in financing activities increased in 2011, compared with 2010. During 2011, Ameren’s cash flow from operating activities of $1.9 billion exceeded its capital expenditures of $1.0 billion and common stock dividend requirements of $375 million. Ameren used this cash as well as cash on hand to repay $581 million of short-term debt and credit agreement borrowings, to redeem $155 million of long-term debt, and to repay $73 million of advances received from generators due to project completion. During 2010, Ameren redeemed $310 million of long-term debt and $52 million of preferred stock.
Ameren Missouri’s cash used in financing activities increased by $96 million in 2011, compared with 2010. During 2011, Ameren Missouri’s cash flow from operating activities of
$1.1 billion exceeded its combined capital and nuclear fuel expenditures of $612 million. Ameren Missouri used this cash to pay common stock dividends of $403 million and to repay $19 million of advances previously received from generators due to project completion. During 2010, Ameren Missouri paid common stock dividends of $235 million; redeemed $70 million of long-term debt, including its 7.69% Series A subordinated debentures; and it redeemed all outstanding shares of its $7.64 Series preferred stock.
Ameren Illinois’ net cash used in financing activities increased by $179 million in 2011 compared with 2010. Ameren Illinois’ common stock dividend increased $194 million compared with 2010. In June 2011, Ameren Illinois’ 6.625% $150 million senior secured notes matured and were repaid and retired using cash on hand. During 2010, in connection with the Ameren Illinois Merger, Ameren Illinois (formerly CILCO) redeemed all of its
preferred stock and all $40 million of its 7.61% Series 1997-2 first mortgage bonds (formerly CIPS). Net repayments of generator advances received for construction increased $25 million in 2011 compared with 2010.
Credit AgreementFacility Borrowings and Liquidity
The liquidity needs of Ameren, Ameren Missouri and Ameren Illinois are typically supported through the use of available cash, short-term intercompany borrowings, and drawings under committed bank credit agreements, or, for Ameren and Ameren Missouri, commercial paper issuances. See Note 4 -– Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information on credit agreements, short-term borrowing activity, commercial paper issuances, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.
The following table presents the committed 2012 Credit Agreements of Ameren, Ameren Missouri, and Ameren Illinois, and the credit capacity available under such agreements, considering reductions for commercial paper issuances and letters of credit, as of December 31, 20122013:
| | | | Expiration | | Borrowing Capacity | | Credit Available | Expiration | | Borrowing Capacity | | Credit Available |
| Ameren and Ameren Missouri: | | | | | | | | |
2012 Missouri Credit Agreement(b) | November 2017 | | $ | 1,000 |
| | $ | 1,000 |
| November 2017 | | $ | 1,000 |
| | $ | 1,000 |
|
| Ameren and Ameren Illinois: | | | | | | | | |
2012 Illinois Credit Agreement(b)(a) | November 2017 | | 1,100 |
| | 1,100 |
| November 2017 | | 1,100 |
| | 1,100 |
|
| Ameren: | | | | | | | | |
| Less: Letters of credit |
| | (c) |
| | (9 | ) | |
| Less: Commercial paper outstanding | | | (c) |
| | (368 | ) |
Less: Letters of credit(b) | | | (c) |
| | (14 | ) |
| Total |
| | $ | 2,100 |
| | $ | 2,091 |
| | $ | 2,100 |
| | $ | 1,718 |
|
| |
| (a) | Certain Ameren subsidiaries not party to the 2012 Credit Agreements may access these credit agreements through intercompany borrowing arrangements. |
| |
(b) | Each credit agreement expires on November 14, 2017. The borrowing sublimitssublimit of Ameren Missouri and Ameren Illinois will mature and expire on November 13, 2013,September 30, 2014, subject to extension on a 364-day basis, as requested by the borrower and approved by the lenders, or for a longer period upon notice by Ameren Illinois of receipt of any and all required federal or state regulatory approvals, as permitted under each credit agreement,the 2012 Illinois Credit Agreement, but in no event later than November 14, 2017. Ameren Missouri andIn October 2013, Ameren Illinois will seekfiled a petition seeking state regulatory approval necessary to extend the maturity date of theirits borrowing sublimitssublimit under the 2012 Illinois Credit AgreementsAgreement to November 14, 2017. |
| |
| (b) | As of December 31, 2013, $11 million of the letters of credit relate to Ameren's ongoing credit support obligations to New AER. See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for additional information. |
The 2012 Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren's Ameren Missouri's, and Ameren Illinois'Missouri's commercial paper programs. AnyEither of the 2012 Credit Agreements are available to Ameren to support borrowingsissuances under Ameren's commercial paper program, subject to borrowing sublimits. The 2012 Missouri Credit Agreement is available to support borrowingsissuances under Ameren Missouri's commercial paper program, and the 2012 Illinois Credit Agreement is available to support borrowings underprogram. Ameren Illinois' commercial paper program.program, under which no commercial paper was ever issued, was terminated in 2013. During 2013, issuances under the
Ameren and Ameren Missouri commercial paper programs were available at a lower interest rate than the interest rate available under the 2012 Credit Agreements. As such, commercial paper issuances were a preferred source of third-party short-term debt relative to credit facility borrowings.
The maximum aggregate amount available to each borrower under each facility is shown in the following table (such amount being such borrower’s “Borrowing Sublimit”):
|
| | | | | | | |
| | 2012 Missouri Credit Agreement | | 2012 Illinois Credit Agreement |
| Ameren | $ | 500 |
| | $ | 300 |
|
| Ameren Missouri | 800 |
| | (a) |
|
| Ameren Illinois | (a) |
| | 800 |
|
Subject to applicable regulatory short-term borrowing authorizations, these credit arrangements are also available to
other Ameren Ameren's non-state-regulated subsidiaries through direct short-term borrowings from Ameren and byto most of Ameren’s non-rate-regulated subsidiaries, including, but not limited to, Ameren Services, through a non-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, Ameren Illinois, and Ameren Services enables Ameren Illinois to make short-term borrowings directly from Ameren. Pursuant to the terms of the unilateral borrowing agreement, the aggregate amount of borrowings outstanding at any time by Ameren Illinois under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding Ameren Illinois external credit facility borrowings or commercial paper issuances, may not exceed $500 million, pursuant to the authorization from the ICC. Ameren Illinois did not borrow under the unilateral borrowing agreement during 20122013 or 2011.2012. Ameren Services is responsible for operation and administration of the money pool agreements. See Note 4 -– Short-term Debt 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 issuance of short-term debt securities by Ameren's utility subsidiaries is subject to approval by FERC under the Federal Power Act. In AprilFebruary 2014, FERC issued an order effective March 17, 2014, authorizing the issuance of up to $1 billion of short-term debt securities for Ameren Missouri. The authorization terminates on March 16, 2016. In September 2012, FERC issued an order authorizing the issuance of up to $1 billion of short-term debt securities forby Ameren Missouri.Illinois. The authorization was effective immediately and terminates on March 31, 2014. On September 20, 2012, FERC issued an order authorizing the issuance of up to $1 billion of short-term debt securities. The authorization was effective as of October 1, 2012 and terminates on September 30, 2014. Ameren Illinois will file for a two-year extension of the FERC short-term borrowing authorization in 2014.
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 liquidity arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements 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) for the years 20122013, 20112012, and 20102011 for the Ameren Companies. The Ameren Companies did not have any redemptions and Genco.repurchases of preferred stock during the years 2013, 2012, and 2011. 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 | | 2012 | | 2011 | | 2010 | Month Issued, Redeemed, Repurchased, or Matured | | 2013 | | 2012 | | 2011 |
| Issuances | | | | | | | | | | | | |
| Long-term debt | | | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | | | |
| 3.90% Senior secured notes due 2042 | September | | $ | 482 |
| | $ | — |
| | $ | — |
| September | | $ | — |
| | $ | 482 |
| | $ | — |
|
| Ameren Illinois: | | | | | | | | | | | | |
| 2.70% Senior secured notes due 2022 | August | | 400 |
| | — |
| | — |
| August | | — |
| | 400 |
| | — |
|
| 4.80% Senior secured notes due 2043 | | December | | 278 |
| | — |
| | — |
|
| Total Ameren long-term debt issuances | | | $ | 882 |
| | $ | — |
| | $ | — |
| | | $ | 278 |
| | $ | 882 |
| | $ | — |
|
| Common stock | | | | | | | | | | | | |
| Ameren: | | | | | | | | | | | | |
| DRPlus and 401(k) | Various | | $ | — |
| | $ | 65 |
| | $ | 80 |
| Various | | $ | — |
| | $ | — |
| | $ | 65 |
|
| Total common stock issuances | | | $ | — |
| | $ | 65 |
| | $ | 80 |
| | | $ | — |
| | $ | — |
| | $ | 65 |
|
| Total Ameren long-term debt and common stock issuances | | | $ | 882 |
| | $ | 65 |
| | $ | 80 |
| | | $ | 278 |
| | $ | 882 |
| | $ | 65 |
|
| Redemptions, Repurchases and Maturities | | | | | | | | | | | | |
| Long-term debt | | | | | | | | | | | | |
| Ameren Missouri: | | | | | | | | | | | | |
| City of Bowling Green capital lease (Peno Creek CT) | Various | | $ | 5 |
| | $ | 5 |
| | $ | 4 |
| Various | | $ | 5 |
| | $ | 5 |
| | $ | 5 |
|
| 5.25% Senior secured notes due 2012 | September | | 173 |
| | — |
| | — |
| September | | — |
| | 173 |
| | — |
|
| 6.00% Senior secured notes due 2018 | September | | 71 |
| | — |
| | — |
| September | | — |
| | 71 |
| | — |
|
| 6.70% Senior secured notes due 2019 | September | | 121 |
| | — |
| | — |
| September | | — |
| | 121 |
| | — |
|
| 5.10% Senior secured notes due 2018 | September | | 1 |
| | — |
| | — |
| September | | — |
| | 1 |
| | — |
|
| 5.10% Senior secured notes due 2019 | September | | 56 |
| | — |
| | — |
| September | | — |
| | 56 |
| | — |
|
| 7.69% Series A subordinated deferrable interest debentures due 2036 | September | | — |
| | — |
| | 66 |
| |
| 1993 5.45% Series pollution control revenue bonds due 2028 | | October | | 44 |
| | — |
| | — |
|
| 4.65% Senior secured notes due 2013 | | October | | 200 |
| | — |
| | — |
|
| Ameren Illinois: | | | | | | | | | | | | |
| 6.625% Senior secured notes due 2011 | June | | — |
| | 150 |
| | — |
| June | | — |
| | — |
| | 150 |
|
| 9.75% Senior secured notes due 2018 | August | | 87 |
| | — |
| | — |
| August | | — |
| | 87 |
| | — |
|
| 6.25% Senior secured notes due 2018 | August | | 194 |
| | — |
| | — |
| August | | — |
| | 194 |
| | — |
|
| 2000 Series A 5.50% pollution control revenue bonds due 2014 | August | | 51 |
| | — |
| | — |
| August | | — |
| | 51 |
| | — |
|
| 7.61% Series 1997-2 first mortgage bonds due 2017 | September | | — |
| | — |
| | 40 |
| |
| 6.20% Series 1992B due 2012 | November | | 1 |
| | — |
| | — |
| November | | — |
| | 1 |
| | — |
|
| Genco: | | | | | | | |
| Senior notes Series D 8.35% due 2010 | November | | — |
| | — |
| | 200 |
| |
| 8.875% Senior secured notes due 2013 | | December | | 150 |
| | — |
| | — |
|
| Total Ameren long-term debt redemptions, repurchases and maturities | | | $ | 760 |
| | $ | 155 |
| | $ | 310 |
| | | $ | 399 |
| | $ | 760 |
| | $ | 155 |
|
| Preferred stock | | | | | | | |
| Ameren Missouri: | | | | | | | |
| $7.64 Series | August | | $ | — |
| | $ | — |
| | $ | 33 |
| |
| Ameren Illinois: | | | | | | | |
| 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 |
| |
| Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities | | | $ | 760 |
| | $ | 155 |
| | $ | 395 |
| |
| |
(a) | In September 2010, Ameren contributed to the capital of Ameren Illinois (formerly IP), without the payment of any consideration, all of the IP preferred stock owned by Ameren ($33 million). IP canceled these preferred shares. |
In June 2012,October 2013, Ameren Ameren Missouri and Ameren Illinois filed a Form S-3 shelfS-8 registration statement registeringwith the issuanceSEC, authorizing the offering of an indeterminate amount4 million additional shares of certain typesits common stock under its 401(k) plan. Shares of securities, which expirescommon stock sold under the 401(k) plan are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in June 2015.the open market or in privately negotiated transactions
Ameren filed a Form S-3 registration statement with the SEC in June 2011, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. In 2013 and 2012, Ameren
shares were purchased in the open market for DRPlus and its 401(k) plan. Under DRPlus and its 401(k) plan, Ameren issued 2.2 million and 3.0 millionshares of common stock in 2011, and 2010, respectively, which were valued at $65 million.
In June 2012, Ameren, Ameren Missouri and $80 million forAmeren Illinois filed a Form S-3 shelf registration statement registering the respective years.issuance of an indeterminate amount of certain types of securities, which expires in June 2015.
The Ameren Companies may sell securities registered under their effective registration statements if market conditions and capital requirements warrant such 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 -– Short-term Debt 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 agreements and in certain of the Ameren Companies’ indentures and articles of incorporation.
At December 31, 20122013, the Ameren Ameren Missouri, Ameren Illinois and GencoCompanies were in compliance with the provisions and covenants contained within their credit agreements, indentures, and articles of incorporation provisions and covenants.incorporation.
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 reasonable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing its current operating performance, liquidity, and credit ratings (see Credit Ratings below), Ameren, Ameren Missouri and Ameren Illinois each believes that it will continue to have access to the capital markets. However, events beyond Ameren's, Ameren Missouri's and Ameren Illinois' 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.
Merchant Generation's operating results and operating cash flows are significantly affected by changes in market prices for power, which have significantly decreased over the past few years. Under the provisions of its indenture, Genco may not
borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or if its leverage ratio is greater than a specified maximum. Based on projections as of December 31, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external third-party sources. Genco's indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control, and if a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. While it remains a business of Ameren, the Merchant Generation segment, including Genco, seeks to fund its operations internally and therefore seeks not to rely on financing from Ameren or external, third-party sources.
Should a financing need arise at Genco, its sources of liquidity include available cash on hand, a return of money pool advances, money pool borrowings at the discretion of Ameren, sale of an asset or multiple assets, or exercising the put option agreement with AERG. Given current power market conditions and cash flow requirements, it is more likely than not that Genco will sell one or more of its three natural gas-fired energy centers before the put option agreement expires on March 28, 2014. Based on current projections, it is probable during 2013 that Genco will need mid-month liquidity from either asset sales or money pool borrowings to support working capital needs. Based on projections as of December 31, 2012, Genco estimates these financing sources are adequate to support its operations in 2013. See Note 14 - Related Party Transactions, under Part II, Item 8, of this report for additional information regarding Genco's put option agreement with AERG and Ameren's guarantee of AERG's contingent obligations under the put option agreement.
Dividends
Ameren paid to its shareholders common stock dividends totaling$388 million, or $1.60 per share, in 2013, $382 million, or $1.60 per share, in 2012, and $375 million, or $1.555 per share, in 2011, and $368 million, or $1.54 per share, in 2010. The payout rate based on net income in 2011 was 72%. The payout of common stock dividends exceeded net income in 2012 and 2010 because of the noncash impairment and other charges recorded during those years. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 23% in 2012, 20% in 2011, and 20% in 2010.
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 doneAs 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. Ameren expects its dividend payout ratio to be between 55% and 70% of earnings over the next few years. On February 8,14, 20132014, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 40 cents per share, payable on March 29,31, 20132014, to stockholdersshareholders of record on March 13,12, 20132014.
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.
Ameren Illinois’ articles of incorporation 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 dividend payments on its common stock. Specifically, Genco cannot pay dividends on its common stock unless the company’s actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of December 31, 2012, of Genco's operating results and cash flows in 2013 and 2014, we did not believe that Genco would achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for each of the subsequent four six-month periods ending June 30, 2013, December 31, 2013, June 30, 2014, or December 31, 2014. As a result, Genco was restricted from paying dividends on its common stock as of December 31, 2012, and we expect Genco will be unable to pay dividends on its common stock in 2013, 2014, and 2015. See Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report for additional
information on Genco's indenture provisions.
Ameren Missouri and Ameren Illinois, 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, 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, Ameren Illinois may not pay any dividend on its stock unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.
In its application for theAmeren has committed to FERC orders approving the Ameren Illinois Merger and the AERG distribution, Ameren committed itself to maintain a minimum of 30% equity in its capital structure at Ameren Illinois following the Ameren Illinois Merger and the AERG distribution.Illinois.
At December 31, 20122013, Ameren, Ameren Missouri and Ameren Illinois were not restricted from paying dividends.
At December 31, 2012,2013, the amount of restricted net assets of wholly owned subsidiaries of Ameren that may not be distributed to Ameren in the form of a loan or dividend was $2 billion.
The following table presents common stock dividends paid by Ameren Corporation to its common stockholdersshareholders and by Ameren’s registrant subsidiaries to Ameren. No dividends were paid by AER to Ameren in 2012, 2011, or 2010.
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Ameren Missouri | $ | 400 |
| | $ | 403 |
| | $ | 235 |
| $ | 460 |
| | $ | 400 |
| | $ | 403 |
|
| Ameren Illinois | 189 |
| | 327 |
| | 133 |
| 110 |
| | 189 |
| | 327 |
|
| Dividends paid by Ameren | 382 |
| | 375 |
| | 368 |
| 388 |
| | 382 |
| | 375 |
|
Certain of the Ameren Companies have issued preferred stock, which provides for cumulative preferred 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 5 -– Long-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, 20122013. 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 | 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) | $ | 6,992 |
| | $ | 355 |
| | $ | 654 |
| | $ | 1,076 |
| | $ | 4,907 |
| $ | 6,048 |
| | $ | 534 |
| | $ | 515 |
| | $ | 1,521 |
| | $ | 3,478 |
|
Interest payments(d) | 4,340 |
| | 428 |
| | 742 |
| | 664 |
| | 2,506 |
| 3,673 |
| | 331 |
| | 605 |
| | 496 |
| | 2,241 |
|
Operating leases(e) | 272 |
| | 31 |
| | 53 |
| | 51 |
| | 137 |
| 117 |
| | 14 |
| | 26 |
| | 26 |
| | 51 |
|
Other obligations(f) | 8,338 |
| | 1,891 |
| | 2,808 |
| | 1,948 |
| | 1,691 |
| 6,349 |
| | 1,519 |
| | 2,188 |
| | 1,201 |
| | 1,441 |
|
| Total cash contractual obligations | $ | 19,942 |
| | $ | 2,705 |
| | $ | 4,257 |
| | $ | 3,739 |
| | $ | 9,241 |
| $ | 16,187 |
| | $ | 2,398 |
| | $ | 3,334 |
| | $ | 3,244 |
| | $ | 7,211 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations(c) | $ | 4,013 |
| | $ | 205 |
| | $ | 229 |
| | $ | 697 |
| | $ | 2,882 |
| $ | 3,764 |
| | $ | 109 |
| | $ | 386 |
| | $ | 814 |
| | $ | 2,455 |
|
Interest payments(d) | 2,846 |
| | 225 |
| | 422 |
| | 372 |
| | 1,827 |
| 2,574 |
| | 211 |
| | 395 |
| | 325 |
| | 1,643 |
|
Operating leases(e) | 123 |
| | 12 |
| | 24 |
| | 25 |
| | 62 |
| 106 |
| | 11 |
| | 22 |
| | 23 |
| | 50 |
|
Other obligations(f) | 5,121 |
| | 841 |
| | 1,738 |
| | 1,619 |
| | 923 |
| 4,308 |
| | 895 |
| | 1,688 |
| | 1,030 |
| | 695 |
|
| Total cash contractual obligations | $ | 12,103 |
| | $ | 1,283 |
| | $ | 2,413 |
| | $ | 2,713 |
| | $ | 5,694 |
| $ | 10,752 |
| | $ | 1,226 |
| | $ | 2,491 |
| | $ | 2,192 |
| | $ | 4,843 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | |
Long-term debt(b)(c) | $ | 1,729 |
| | $ | 150 |
| | $ | — |
| | $ | 379 |
| | $ | 1,200 |
| $ | 1,859 |
| | $ | — |
| | $ | 129 |
| | $ | 707 |
| | $ | 1,023 |
|
Interest payments(d) | 790 |
| | 106 |
| | 188 |
| | 174 |
| | 322 |
| 1,086 |
| | 107 |
| | 210 |
| | 171 |
| | 598 |
|
Operating leases(e) | 7 |
| | 1 |
| | 2 |
| | 2 |
| | 2 |
| 7 |
| | 2 |
| | 2 |
| | 2 |
| | 1 |
|
Other obligations(f) | 2,446 |
| | 695 |
| | 796 |
| | 216 |
| | 739 |
| 1,960 |
| | 573 |
| | 470 |
| | 171 |
| | 746 |
|
| Total cash contractual obligations | $ | 4,972 |
| | $ | 952 |
| | $ | 986 |
| | $ | 771 |
| | $ | 2,263 |
| $ | 4,912 |
| | $ | 682 |
| | $ | 811 |
| | $ | 1,051 |
| | $ | 2,368 |
|
| |
| (a) | Includes amounts for registrant and nonregistrant Ameren subsidiaries and intercompany eliminations. |
| |
| (b) | Excludes fair-market value adjustments of Ameren Illinois' long-term debt of $4 million. |
| |
| (c) | Excludes unamortized discount and premium of $15$14 million at Ameren, $7 million at Ameren Missouri and $67 million at Ameren Illinois. |
| |
| (d) | The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 20122013. |
| |
| (e) | Amounts related tofor certain land-related leases have indefinite payment periods. The annual obligation of $2 million, $1 million, and $1 million for Ameren, Ameren Missouri and Ameren Illinois, respectively, for these items is included in the Less than 1 Year, 1 - 3 Years, and 3 - 5 Years columns. |
| |
| (f) | See Other Obligations in Note 15 -– Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items included herein. |
As of December 31, 20122013, the amounts of unrecognized tax benefits (detriments) under the authoritative accounting guidance for uncertain tax positions were $90 million, $156 million, $13631 million, and $13(1) million for Ameren, Ameren Missouri, and Ameren Illinois, 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, 2012,2013, none of the Ameren Companies had 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. See Note 14 - Related Party16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for Ameren (parent) guarantees and letters of credit issued to support New AER based on behalf of its subsidiaries.the transaction agreement with IPH.
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 | Baa3Baa2 | BBB-BBB+ | BBB |
| Senior unsecured debt | Baa3Baa2 | BB+BBB | BBB |
| Commercial paper | P-3P-2 | A-3A-2 | F2 |
| Ameren Missouri: | | | |
| Issuer/corporate credit rating | Baa2Baa1 | BBB-BBB+ | BBB+ |
| Secured debt | A3A2 | A | A |
| Senior unsecured debt | Baa1 | BBB+ | AA- |
| Ameren Illinois: | | | |
| Issuer/corporate credit rating | Baa2Baa1 | BBB-BBB+ | BBB- |
| Secured debt | A3A2 | BBB+A | BBB+ |
| Senior unsecured debt | Baa2Baa1 | BBB-BBB+ | BBB |
Genco: | | | |
Issuer/corporate credit rating | — | CCC+ | CC |
Senior unsecured debt | B2 | CCC+ | CCC- |
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.
Collateral Postings
Any adverse change in the Ameren Companies’ and Genco's 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 natural gas supply, among other things, resulting in a potential negative impact on earnings. Cash collateral postings and prepayments made with external parties, including postings related to exchange-traded contracts at December 31, 20122013, were $98$30 million, $13$15 million, and $58$15 million at Ameren, Ameren Missouri and Ameren Illinois, respectively. The amount of cashCash collateral posted by external counterparties posted with Ameren and Ameren Illinois was $5$2 million and $2 million, respectively, at December 31, 20122013. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at December 31, 20122013, could have resulted in Ameren, Ameren Missouri, or Ameren Illinois or AER being required to post additional collateral or other assurances for certain trade obligations amounting to $245$122 million, $71 million, $84$67 million, and $90$55 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, 20122013, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois and AER could be required to post additional
collateral or other assurances for certain trade obligations up to $174$1 million, $6 million, $-$1 million, and $168$- million, respectively. If market prices were 15% lower than December 31, 20122013, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren, Ameren Missouri, or Ameren Illinois and AER could be required to post additional collateral or other assurances for certain trade obligations up to $152$17 million, $4 million, $31$2 million, and $117$15 million, respectively.
The transaction agreement between Ameren and IPH required Ameren to maintain its financial obligations with respect to all credit support provided to New AER for all transactions entered into prior to the closing of the divestiture on December 2, 2013, for up to 24 months after the closing. The permitted forms of credit support for each counterparty agreement could include one or more of the following: cash, a letter of credit, a guarantee, or other credit support alternatives. Ameren's exposure related to the continuation of credit support provided to New AER after December 2, 2013, depends upon the transactions and counterparty agreements that AER and its subsidiaries had in effect as of December 2, 2013, and any changes in the market prices of these transactions that require an increase or decrease in collateral postings. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation is secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). As of December 31, 2013, Ameren provided $190 million in guarantees and letters of credit totaling $11 million relating to its credit support of New AER. See Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for additional information regarding Ameren (parent) guarantees and Ameren's transaction agreement divesting New AER to IPH.
Immediately prior to the transaction agreement closing on December 2, 2013, the cash collateral provided to New AER by Ameren through money pool borrowings was converted to a note payable to Ameren, which is payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. The balance of the note was $18 million at December 31, 2013; it will vary over the 24-month period as cash collateral requirements for New AER change. Changes in commodity prices could trigger additional collateral postings and prepayments for New AER and thus affect the balance of the note. If market prices were 15% higher than December 31, 2013, levels in the next 12 months and 20% higher thereafter through the end of the term of the commodity contracts, then Ameren could be required to provide additional credit support to IPH up to $105 million. If market prices were 15% lower than December 31, 2013, levels in the next 12 months and 20% lower thereafter through the end of the term of the commodity contracts, then Ameren could be required to provide IPH with additional credit support up to $43 million.
OUTLOOK
Ameren seeks to earn competitive returns on its investments in its businesses. Ameren Missouri and Ameren Illinois are seeking to improve their regulatory frameworks and cost recovery mechanisms. At the same time, Ameren's rate-regulated businesses aremechanisms and simultaneously pursuing constructive regulatory outcomes within existing frameworksframeworks. Ameren Missouri and Ameren Illinois are seeking to align their overall spending, both operating and capital, with economic conditions and cash flows provided by their regulators. Consequently, Ameren's rate-regulated businesses are focused on minimizing the gap between allowed and earned returns on equity. Ameren's Merchant Generation segment maintains a fleet of coal-fired and natural gas-fired energy centers. In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. As a result, Ameren no longer considers the Merchant Generation segment to be a core component of its future business strategy. Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation segment's, including Genco's, reliance on Ameren's financial support and shared services support. Ameren intends to allocate its capital resources to those business opportunities including electric and natural gas transmission, whichthat offer the most attractive risk-adjusted return potential.
Below are some key trends, events, and uncertainties that are reasonably likely to affect the Ameren Companies' results of operations, financial condition, or liquidity, as well as their ability to achieve strategic and financial objectives, for 20132014 and beyond.
Rate-Regulated Operations
Ameren's strategy for earning competitive returns on its rate-regulated investments involves meeting customer energy needs in an efficient fashion, working to enhance regulatory frameworks, making timely and well-supported rate case filings, and aligning overall spending with those rate case outcomes, economic conditions, and return opportunities.
In December 2012,Ameren continues to pursue its plans to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the construction of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. ATXI obtained a certificate of public convenience and necessity and project approval from the ICC issued an order with respectfor the entire Illinois Rivers project. A full range of construction activities is scheduled in 2014. The first sections of the Illinois Rivers project are expected to be completed in 2016. The last section of this project is expected to be completed in 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects approved by MISO. These two projects are expected to be completed in 2018. The total investment in these three projects is expected to be $1.4 billion through 2019. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $850 million in electric transmission assets over the next five years to address load growth and reliability requirements.
In July 2013, Illinois enacted the Natural Gas Consumer, Safety and Reliability Act, which encourages Illinois natural gas utilities to accelerate modernization of the state's natural gas infrastructure and provides additional ICC oversight of natural gas utility performance. The law allows natural gas utilities the option to file for, and requires the ICC to approve, a rate rider mechanism to recover costs of certain natural gas infrastructure investments made between rate cases. The law does not require a minimum level of
investment. Ameren Illinois expects to begin including investments under this regulatory framework in 2015. Ameren Illinois' update IEIMA filing approving an electric delivery service revenue requirement that was a $70 million decrease fromdecision to accelerate modernization of its natural gas infrastructure under this regulatory framework is dependent upon multiple considerations, including the requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The new rates
became effective on January 1, 2013. We believe that Ameren Illinois' participation in the performance-based formula ratemaking framework pursuant to the IEIMA will better enable Ameren Illinois to earn its allowed return on equity for its electric delivery service business. Thisunder this framework is expected to givecompared with other Ameren and Ameren Illinois the earnings predictability to invest in modernizing its distribution system. However, the ICC's orders in 2012 for Ameren Illinois' initial and update filings jeopardize Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Ameren Illinois has appealed both of the ICC's 2012 electric rate orders to the courts and is also seeking a legislative solution to address the ICC's implementation of the IEIMA. Although Ameren Illinois intends to meet its IEIMA capital spending requirements, it is proceeding on a slower investment schedule than previously contemplated until the uncertainty surrounding how the IEIMA will ultimately be implemented is removed.options.
The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for customer billings for that year. Consequently, Ameren Illinois' 20132014 electric delivery service revenues will be based on its 20132014 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 20132014 revenue requirement is expected to be higher than the 2013 revenue requirement, due to an expected increase in recoverable costs, rate base growth, and expected increase in the monthly average of United States treasury bonds.
In December 2013, the ICC issued an order with respect to Ameren Illinois' annual update IEIMA filing. The ICC approved a net $45 million decrease in Ameren Illinois' electric delivery service rates, which represents an annual revenue requirement increase of $23 million primarily due to higher recoverable costs in 2012 compared to 2011, offset by a $68 million refund to customers relating to the 2012 revenue requirement even though the amount added to the monthly average yields of the 30-year United States treasury bonds will decrease to 580 basis points in 2013 from 590 basis points in 2012, due to expected increases in recoverable costs and rate base growth.
Ameren Illinois' 2012 revenue requirement under the IEIMA framework was lower than the revenue requirement included in both the ICC's 2010 electric rate order and the ICC's September 2012 order related to Ameren Illinois' initial IEIMA filing. Consequently, Ameren Illinois recorded a $55 million regulatory liability to represent its estimate of the probable decrease in electric delivery service revenues expected to be approved by thereconciliation. The ICC decision issued in December 2013 to provideestablished new rates that became effective January 1, 2014. These rates will affect Ameren Illinois recovery of all prudently and reasonably incurred costs and an allowed rate of return on common equity for 2012. Any decrease in electric delivery serviceIllinois' cash flows during 2014, but not its operating revenues, approvedwhich will instead be determined by the ICC in December 2013IEIMA's 2014 revenue requirement reconciliation. The 2014 revenue requirement reconciliation will be reflected as a regulatory asset or liability that will be collected from or refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA.in 2016.
In JanuaryDecember 2013, Ameren Illinois filed a request with the ICC toissued an order that authorized a $32 million increase itsin Ameren Illinois’ annual revenues for natural gas delivery service by $50 million. In an attempt to reduce regulatory lag, Ameren Illinois usedrevenues. This request was based on a future test year of 2014, in this proceeding. A decision in this proceeding is requiredwhich improves the ability to earn returns allowed by December 2013.
In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million, including $84 million related to an anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its 2011 electric rate order. The
annual increase also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other non-fuel costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets.regulators. The new rates became effective January 1, 2014.
On February 13, 2014, Ameren Missouri’s largest customer, Noranda, and 37 residential customers filed an earnings complaint case and a rate design complaint case with the MoPSC. In the earnings complaint case, Noranda and the residential customers asserted that Ameren Missouri’s electric delivery service business is earning more than the 9.8% return on January 2, 2013.
Theequity authorized in the MoPSC's December 2012 electric rate order approvedand requested the MoPSC to approve a reduction of the authorized return on equity to 9.4%. The rate design complaint case seeks to reduce Noranda’s electricity cost with an offsetting increase in electricity cost for Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs,Missouri’s other customers. The rate design complaint case asks the MoPSC to expedite its decision and associated cost recovery mechanisms and incentive awards. Beginninggrant relief by August 1, 2014. The MoPSC has no time requirement by which it must issue an order in 2013,these cases. Ameren Missouri opposes both requests filed by Noranda and the residential customers and will invest approximately $147 million over the next three years for energy efficiency programs. The order allows for Ameren Missouri to collect its program costs and 90%vigorously
defend itself.
As theywe continue to experience cost recovery pressures,increases and make infrastructure investments, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri expects to file an electric service rate case in July 2014. Ameren Missouri and Ameren Illinois will also seek, as necessary, legislative solutions to address cost recovery pressures.pressures and to support investment in their energy infrastructure. These pressures include a weak economy, customer conservation efforts, the impacts of energy efficiency programs, increased investments and expected future investments for environmental compliance, system reliability improvements, and new baseloadgeneration capacity, including renewable energy requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property and income taxes, and higher insurance premiums as a result of insurance market conditions and industry loss experience, among other things.
The MoPSC issued an order, in April 2011, with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. The order required Ameren Missouri to refund $18 million, including $1 million for interest, to customers related to pretax earnings associated with certain long-term partial requirements sales made by Ameren Missouri after the loss of Noranda's load in a severe ice storm in January 2009. Ameren Missouri appealed this decision to the Cole County Circuit Court, which overturned the MoPSC's April 2011 order. The Cole County Circuit Court decision is being appealed by the MoPSC to the Missouri Court of Appeals. It is possible that
the MoPSC could order additional refunds of approximately $25 million related to pretax earnings associated with these long-term partial requirements sales in periods after September 2009, and this could result in a charge to earnings in the period in which such an order is received. Separately, Ameren Missouri filed a request with the MoPSC in July 2011 for an accounting authority order that would allow Ameren Missouri to recover fixed costs totaling $36 million due to the loss of load caused by the severe 2009 ice storm in a future electric rate case. If the courts ultimately rule in favor of Ameren Missouri's position regarding the classification of the long-term partial requirements sales, Ameren Missouri would no longer seek to recover from customers the sum covered by the accounting authority order.
Ameren and Ameren Missouri also are pursuing recovery from insurers, through litigation, for reimbursement of unpaid liability insurance claims for a December 2005 breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity could be adversely affected if Ameren Missouri’s remaining liability insurance claims of $68 million as of December 31, 2013, are not paid by insurers.
Ameren Missouri's Callaway energy center's next scheduled refueling and maintenance outage at its Callaway energy center will be in the springfall of 2013. The expected duration of this outage is approximately 40 days.2014. During a scheduled outage, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri's purchased power costs may increase and the amount of excess power available for sale decreases,may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, resulting in limited impactimpacts to earnings. Electric operating revenues in 2013 did not fully offset the additional maintenance costs incurred during the 2013 outage, because revenues relating to the additional maintenance costs are recovered over 18 months.
Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity.
As of December 31, 2013, Ameren Missouri had capitalized $69 million of costs incurred to license additional nuclear generation at its Callaway energy site. If efforts are abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.
Environmental regulations, as well as future initiatives, including those related to greenhouse gas emissions, and global climate change, could result in significant increases in capital expenditures and operating costs. The compliance costsThese expenses could be prohibitive at
some of Ameren Missouri's coal-fired energy centers, particularly at its Meramec energy center. The expected return from these investments, at current market prices for energy and capacity, might not justify the requiredAmeren Missouri's capital expenditures for their continued operation.
Ameren intendsare subject to allocate its capital to those investment opportunities with the highest expected risk-adjusted returns. Ameren believes that because of its strategic locationMoPSC prudence reviews, which could result in the country, electric transmission may provide it with such an opportunity. MISO has approved three projects, which will be developed by ATXI. The first project, Illinois Rivers, involves the building of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. Design and planning work on the first sections of this project have begun and right-of-way acquisitions are scheduled to commence in late 2013 after receipt of a certificate of public convenience and necessity, which ATXI requested from the ICC in November 2012. Construction is expected to begin in 2014. The first sections of the Illinois Rivers project are expected to be in service in 2016. The last section of this project is expected to be completed in 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two
projects approved by MISO in its current transmission expansion plan. These two projects are expected to be completed in 2018. The estimated total investment in these three projects is expected to be more than $1.3 billion through 2019. FERC has approved transmission rate incentives for the three MISO approved projectscost disallowances as well as for the Big Muddy River project. The Big Muddy River project, located primarily in southern Illinois, is being evaluated for inclusion in MISO's transmission expansion plans. Separate from the ATXI projects discussed above,prolonged periods before recovery of these investments occur.
Both Ameren Illinois expectsand ATXI have FERC authorization to invest approximately $1 billion in electric transmission assets over the next five years to address load growth and reliability requirements.
In November 2012, FERC approvedemploy a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois'each company’s electric transmission business. Based on its forward-looking rate calculation,With the projected rates that became effective on January 1, 2013,2014, Ameren Illinois adjustedIllinois’ 2014 revenue requirement for its electric transmission business is expected to increase by $15 million over 2013 levels due to rate base growth. With the projected rates to reflect an increase in its transmissionthat became effective on January 1, 2014, ATXI’s 2014 revenue requirement of $29 million. Thefor its electric transmission business is expected to increase by $21 million over 2013 levels due to rate base growth, primarily relating to the Illinois Rivers project.
In November 2013, a customer group filed a complaint case with FERC seeking a reduction in Ameren Illinois'the allowed return on common equity, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed return on common equity for MISO transmission revenue requirementowners is subject to a revenue requirement reconciliation, which12.38%. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also result in a refund for transmission service revenues earned after the filing of the complaint case in November 2013. FERC has not issued an adjustmentorder in this case, and it is under no deadline to revenues based on the actual revenue requirement in 2013.do so.
For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, the FAC prudence review and related appeal, Taum Sauk matters, and separate FERC orders impactingaffecting Ameren Missouri and Ameren Illinois, see Note 2 -– Rate and Regulatory Matters, Note 10 -– Callaway Energy Center, and Note 15 -– Commitments and Contingencies under Part II, Item 8, of this report.
Merchant Generation Operations
Ameren no longer considers the Merchant Generation segment to be a core component of its future business strategy. As a result, Ameren intends to exit its Merchant Generation segment before the end of the previously estimated useful lives of that segment's long-lived assets. In consideration of this determination, Ameren has begun planning to reduce, and ultimately to eliminate, the Merchant Generation segment's, including Genco's, reliance on Ameren's financial support and shared services support. Based on Ameren's intention to exit its Merchant Generation segment, Ameren recorded an asset impairment charge in December 2012 to reduce the carrying value of all of the Merchant Generation segment's coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values. See Note 17 - Impairment and Other Charges under Part II, Item 8, of this report for additional information. Ameren's date and method of exit from the Merchant Generation business is currently uncertain. Exit strategies may include the sale of all or parts of the Merchant Generation business and the restructuring of all or a portion of Ameren's equity position in Genco. Once a plan of disposal is finalized, Ameren's implementation of that plan may result in long-lived asset impairments, disposal-related losses, contingencies,
reduction of existing deferred tax assets, and other consequences that are currently unknown.
As a result of Merchant Generation's reduced net property and plant carrying value, Ameren estimates that annual depreciation expense will be reduced by approximately $75 million, before taxes.
Ameren could recognize additional, material long-lived asset impairment charges in the future if estimated undiscounted cash flows no longer exceed carrying values for long-lived assets. This may occur either as a result of factors outside Ameren's control, such as changes in market prices of power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of Merchant Generation's energy centers, and also as a result of factors that may be within Ameren's control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell its energy centers. As of December 31, 2012, the net book value of Ameren's Merchant Generation long-lived assets was $748 million.
The Merchant Generation segment expects to have available generation from its coal-fired energy centers of 31 million megawatthours in any given year. However, based on currently expected power prices, the Merchant Generation segment expects to generate approximately 27.5 million megawatthours in 2013, with approximately 95% of this generation expected to be from coal-fired energy centers.
Power prices in the Midwest affect the amount of revenues and cash flows the Merchant Generation segment can realize by marketing power into the wholesale and retail markets. Ameren's Merchant Generation segment is adversely affected by the declining market price of power for any unhedged generation. Market prices for power have decreased over the past several years, especially sharply during the first quarter of 2012.
As of December 31, 2012, Marketing Company had hedged approximately 25.5 million megawatthours of Merchant Generation's expected generation for 2013, at an average price of $36 per megawatthour. For 2014, Marketing Company had hedged approximately 14 million megawatthours of Merchant Generation's forecasted generation sales at an average price of $38 per megawatthour. For 2015, Marketing Company had hedged approximately 6.5 million megawatthours of Merchant Generation's forecasted generation sales at an average price of $40 per megawatthour. Any unhedged forecasted generation will be exposed to market prices at the time of sale. As a result, any new physical or financial power sales may be at price levels lower than previously experienced and lower than the value of existing hedged sales.
To further reduce cash flow volatility, Merchant Generation seeks to hedge fuel costs consistent with power sales. As of December 31, 2012, for 2013 Merchant Generation had hedged fuel costs for approximately 25 million megawatthours of coal and up to 27 million megawatthours of base transportation at about $23 per megawatthour. For
2014, Merchant Generation had hedged fuel costs for approximately 13 million megawatthours of coal and up to 21 million megawatthours of base transportation at about $24 per megawatthour. For 2015, Merchant Generation had hedged fuel costs for approximately 6 million megawatthours of coal and up to 20 million megawatthours of base transportation at about $26 per megawatthour. See Item 7A - Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about the percentage of fuel and transportation requirements that are price-hedged for 2013 through 2017.
In June 2012, FERC approved MISO's proposal to establish an annual capacity market within the RTO. MISO's inaugural annual capacity auction will be held in March 2013 for the June 2013 to May 2014 planning year. Participation in MISO's capacity auction is voluntary for load-serving entities as they will continue to be able to plan to meet all of their resource requirements outside of the auction, including through self-supply and/or bilateral contracts.
The Merchant Generation segment continues to seek revenue growth opportunities. One such opportunity is Marketing Company's ability to sell additional electric capacity into PJM. Capacity market prices within PJM are higher than capacity market prices within MISO. In addition to the capacity related to Genco's Elgin energy center, which is located within PJM, Marketing Company expects to sell additional capacity associated with 681 megawatts of PJM-approved transmission capacity from MISO to PJM. This includes 84 megawatts of transmission capacity associated with AERG energy centers from October 2011 forward, and an additional 301 megawatts and 296 megawatts of transmission capacity associated with AERG and Genco energy centers, respectively, from June 2015 forward. Another revenue growth opportunity is Marketing Company's efforts to sell power to residential and small commercial customers in Illinois. Marketing Company is actively pursuing sales to customers choosing the state of Illinois municipal aggregation alternative for electric power supply. Marketing Company's sales to municipal aggregation customers at retail prices provide margins above the current wholesale market prices. Marketing Company will attempt to expand the volume of its sales to residential and small commercial customers through the municipal aggregation initiative.
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• | In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO2 emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance. The order also established a schedule of milestones for completion of various aspects of the installation and completion of the scrubber project at Genco's Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.
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EEI reduced its workforce in 2012. Going forward, the workforce reduction is expected to reduce EEI's annual pretax other operations and maintenance expenses by $2 million to $3.5 million. Additionally, EEI's management and labor union postretirement medical benefit plans were amended in 2012 to adjust for moving to a Medicare Advantage plan, which resulted in a reduction of the benefit obligation. Ameren estimates the pretax impact of the lower benefit obligation will result in a $5 million to $10 million reduction in postretirement benefits expense during 2013.
Liquidity and Capital Resources
The Ameren Companies seek to maintain access to the capital markets at commercially attractive rates in order to fund their businesses. The Ameren Companies seek to enhance regulatory frameworks and returns in order to improve cash flows, credit metrics, and related access to capital for Ameren's rate-regulated businesses.
The Merchant Generation segment seeks to fund its operations internally and not to rely on financing from Ameren or external, third-party sources. The Merchant Generation segment will continue to seek to defer or reduce capital and operating expenses, to sell certain assets, and to take other actions as necessary to seek to fund its operations internally while maintaining safe and reliable operations. Consistent with these objectives, in March 2012, Genco entered into a put option agreement with AERG for the potential saleuse of the Grand Tower, the Gibson City, and the Elgin energy centers, in order to provide an additional source of liquidity, if needed in the future. Ameren and AERG do not expect to extend the put option agreement beyond March 28, 2014. Given power market conditions and cash flow requirements, it is more likely than not that Genco will sell one or more of its three natural gas-fired energy centers before the put option expires to improve its liquidity. Based on current projections, it is probable during 2013 that Genco will need mid-month liquidity from either asset sales or money pool borrowings to support working capital needs. Based on projections as of December 31, 2012, Genco estimates that these financing sources are adequate to support its operations in 2013.
Under its indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or if its leverage ratio is greater than a specified maximum. Based on projections as of December 31, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco's indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control. If a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. A decision by Ameren not to provide funding to Genco
in the event a financing need arises could cause Genco to undertake a corporate restructuring. Under such circumstances, Ameren may cease to own all or a portion of its equity interest in Genco, and Ameren may incur restructuring costs.
Genco cannot pay dividends on its common stock unless the company's actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. After a December 31, 2012 review of Genco's operating results and cash flows, we do not expect that Genco will achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for each of the four six-month periods ending June 30, 2013, December 31, 2013, June 30, 2014 or December 31, 2014. As a result, Genco was restricted from paying dividends on its common stock as of December 31, 2012. We expect that Genco will be unable to pay dividends on its common stock through at least December 31, 2015.
Based on current projections for 2013, AER and Genco each expects its operating cash flows and short-term borrowings to approximatefund capital expenditures and other long-term investments may periodically result in a working capital deficit, as defined by current liabilities exceeding current assets, as was the case at December 31, 2013. The working capital deficit as of December 31, 2013, was primarily the result of current maturities of long-term debt. Ameren is currently evaluating refinancing options for these current maturities including, in part, through the issuance of long-term notes. In addition, Ameren had $368 million of commercial paper issuances outstanding as of December 31, 2013. With the 2012 Credit Agreements,
Ameren has access to $2.1 billion of credit capacity of which $1.7 billion was available at December 31, 2013.
In May 2014, $425 million of Ameren's 8.875% senior unsecured notes and $104 million of Ameren Missouri's 5.50% senior secured notes will mature. Ameren expects to refinance its nonoperatingparent company debt at a lower interest rate, which will reduce its interest expense.
Ameren expects its cash flow requirementsused for capital expenditures and dividends to exceed cash provided by operating activities over the next few years.
As of December 31, 2013, Ameren had $408 million in 2013. Included in this 2013 projection, AER and Genco expect to receive income tax benefits through the tax allocation agreement of approximately $100 millionfrom federal and $60 million, respectively. These estimates may change significantly depending on the taxable income or loss of Ameren and each of its subsidiaries and also assume Ameren's continued ownership of AER and Genco. Additional sources of liquidity from either asset sales or money pool borrowings may be required to support AER and Genco's daily working capital needs.
As of December 31, 2012, Ameren had approximately $605 million in federal income taxstate net operating loss carryforwards (Ameren Missouri - $175– $64 million and Ameren Illinois - $175– $95 million) and $87$118 million in federal and state income tax credit carryforwards (Ameren Missouri - $11– $12 million and Ameren Illinois - $- million)– none). TheseConsistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities in 2014 for Ameren Missouri into 2014, and into 2015 for Ameren and Ameren Illinois consistent withinto 2016. In addition, Ameren has $85 million of expected income tax refunds and state overpayments that will offset income tax liabilities into 2016. These tax benefits, primarily at the Ameren (parent) level, when realized, will be available to finance electric transmission investments, specifically ATXI's Illinois Rivers project. These tax allocation agreement.benefits are projected to reduce or eliminate Ameren's need to issue additional equity to fund these investments over the next few years.
In December 2011, the IRS issued new guidance in the form of temporary regulations on the treatment of amounts paid to acquire, produce, or improve tangible property and dispositions of such property with respect to electric transmission, distribution, and generation assets as well as natural gas transmission and distribution assets. These new rules are required to be implemented no later than January 1, 2014. This new guidance may change how Ameren determines whether expendituresFinal regulations related to plant and equipment are deducted as repairs or capitalized for income tax purposes. Until Ameren completes itsthis guidance were issued in September 2013. Based on a preliminary evaluation of the new guidance, Ameren cannot estimate its impact on Ameren's results of operation, financial position, and liquidity.
Depending on the date and method of exit from the Merchant Generation business, Ameren may not be ableexpects to fully recover the deferred tax assets that are on its
December 31, 2012 balance sheet. Ameren will be required to expense or create a valuation allowance for any portion of its deferred tax assets that it cannot use to offset future taxable income. At this time, based on the uncertainty regarding the form, structure, and timing of its exit from the Merchant Generation business, Ameren cannot determine if it will ultimately be required to expense or establish a valuation allowance for any portion of its existing deferred tax assets.
The American Taxpayer Relief Act of 2012, enacted into law on January 2, 2013, includes provisions accelerating the depreciation of certain property for income tax purposes. Qualifying property placed into service in 2013 is eligible for 50% bonus depreciation. It is expected that additional bonus depreciation deductions in 2013 will, after the use of net operating loss and tax credit carryforwards, decrease Ameren's income tax payments in 2015 by approximately $120 million. In addition, if these deductions had been taken into account at December 31, 2012, the amount of current accumulated deferred income tax assets would have decreased by approximately $120$40 million for Ameren (Ameren Missouri - $45$24 million and Ameren Illinois - $35$16 million) with a corresponding decrease in long-term accumulated deferredfederal income tax liabilities.net operating loss carryforward benefits to offset tax liabilities related to the accounting method change that Ameren expects to file with the IRS in 2014 in connection with this new guidance.
In November 2012, the Ameren Companies entered into multiyear credit agreements that cumulatively provide $2.1 billion of credit through November 14, 2017. The 2010 Genco Credit Agreement was terminated in November 2012 and not replaced. See Note 4 -– Short-term Debt and Liquidity under Part II, Item 8, of this report for additional information regarding the 2012 Credit Agreements. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital, or financing plans.
Ameren investments required to achieve compliance with known environmental laws and regulations from 2013 to 2022 are expected to be more than $1.5 billion. Ameren continues to closely monitor pending laws and regulations to determine the most appropriate investment approach. Some energy centers may be refueled, retired, replaced or mothballed depending on environmental laws and regulations and market conditions. Any pollution control investments will result in decreased energy center availability during construction and significantly higher ongoing operating expenses. Any pollution control investments at Ameren Missouri are expected to be recoverable from ratepayers, subject to prudence reviews. Regulatory lag may materially affect the timing of such recovery and returns on the investments, and therefore affect our cash flows and related financing needs. The recoverability of amounts expended in our Merchant Generation segment, if retained by Ameren for the entire period, will depend on whether market prices for power change to reflect increased environmental costs for coal-
fired energy centers.
The above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, or liquidity. These
strategies may include acquisitions, divestitures, and 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, or liquidity.
REGULATORY MATTERS
See Note 2 -– Rate and Regulatory Matters under Part II, Item 8, of this report.
ACCOUNTING MATTERS
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 that 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.
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Regulatory Mechanisms and Cost Recovery
The Ameren Companies defer costs in accordance with authoritative accounting guidance, and make investments that they assume will be collected in future rates.
Regulatory environment and external regulatory decisions and requirements
Anticipated future regulatory decisions and our assessment of their impact
Impact of deregulation, rate freezes, prudency reviews, and opposition during the ratemaking process andthat may limit our ability to timely recover costs
Ameren Illinois’ assessment of and ability to estimate the current year’s electric delivery service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA performance-based formula ratemaking process.process
Ameren Illinois’ and ATXI's assessment of and ability to estimate the current year’s electric transmission service costs to be reflected in revenues and recovered from customers in a subsequent year under the FERC ratemaking process
Estimate of revenue recovery from MEEIA
Basis for Judgment
We determine which costs are recoverable by consultingreviewing previous rulings by state regulatory authorities in jurisdictions where we operate and any other factors that may indicate whether cost recovery is probable. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of recovery or that plant assets are probable of disallowance, we record a charge to earnings, which could be material. Ameren Illinois estimates its annual revenue requirement pursuant to the IEIMA for interim periods by using internal forecasted information, such as projected operations and maintenance expenses, depreciation expense, taxes other than income taxes, and rate base, as well as published forecasted data regarding that year's monthly average yields of the 30-year United States treasury bonds. Ameren Illinois estimates its annual revenue requirement as of December 31st of each year using that year's actual operating results and assesses the probability of recovery of or refund to customers that the ICC will order at the end of the following year. Variations in costs incurred, investments made, or orders by the ICC or courts can result in a subsequent change in Ameren Illinois' estimate. Ameren Illinois and ATXI follow a similar process for their FERC electric transmission businesses. See Note 2 -– Rate and Regulatory Matters under Part II, Item 8, of this report for quantification of these assets for each of the Ameren Companies.
Derivative Financial Instruments
We account for derivative financial instruments and measure their fair value in accordance with authoritative accounting guidance, which requires the identification and classification of a derivative and its fair value. 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.
Our ability to identify derivatives
Our ability to assess whether derivative contracts qualify for the NPNS exception
Our ability to consume or produce notional values of derivative contracts
Market conditions in the energy industry, especially the effects of price volatility and liquidity
Valuation assumptions on longer-term contracts due to lack of observable inputs
Effectiveness of derivatives that have been designated as hedges
Counterparty default risk
Basis for Judgment
We evaluate contracts to determine whether they contain derivatives. Determining whether or not a contract qualifies as a derivative under authoritative accounting guidance requires us to exercise significant judgment in interpreting the definition of a derivative and applying that definition. 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. We determine whether to exclude the fair value of certain derivatives from valuation under the NPNS provisions of authoritative accounting guidance after 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, guided by the best internal and external information available.
Valuation of Long-Lived Assets and Asset Retirement Obligations
We periodically assess the carrying value of our 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.
Changes in business, industry, laws, technology, or economic and market conditions
Valuation assumptions and conclusions, including an appropriate discount rate and terminal year earnings multiple.
Our assessment of market participants
Estimated useful lives or duration of ownership of our significant long-lived assets
Actions or assessments by our regulators
Identification of an asset retirement obligation and assumptions about the timing of asset removals
Basis for Judgment
Whenever events or changes in circumstances indicate a valuation may have changed, we use various methodologies that we believe market participants would use to determine valuations 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 asset retirement obligations. See Impairment and Other Charges in Management's Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 17 - Impairment and Other Charges under Part II, Item 8, of this report for additional information of our long-lived asset impairment evaluation and charges recorded.
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.
Future rate of return on pension and other plan assets
Valuation inputs and assumptions used in the fair value measurements of plan assets excluding those inputs that are readily observable
Interest rates used in valuing benefit obligations
Health care cost trend rates
Timing of employee retirements and mortality assumptions
Ability to recover certain benefit plan costs from our ratepayers
Changing market conditions that may affect investment and interest rate environments
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 and disclosing 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.
Estimating financial impact of events
Estimating likelihood of various potential outcomes
Regulatory and political environments and requirements
Outcome of legal proceedings, settlements, or other factors
Changes in regulation, expected scope of work, technology or timing of environmental remediation
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. If no estimate is better than another within our range of estimates, we record as our best estimate of a loss the minimum value of our estimated range of outcomes. 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 Energy Center, and Note 15 -– Commitments and Contingencies, and Note 16 – Divestiture Transactions and Discontinued Operations under Part II, Item 8, of this report for information on the Ameren Companies’ contingencies.
Accounting for Income Taxes
Based on authoritative accounting guidance, we record the provision for income taxes, deferred tax assets and liabilities, and a valuation allowance against net deferred tax assets, if any. See Note 13 -– Income Taxes under Part II, Item 8, of this report.
Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations
Estimates of the amount and character of future taxable income
Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled
Effectiveness of implementing tax planning strategies
Changes in income tax laws
Results of audits and examinations of filed tax returns by taxing authorities
Basis for Judgment
The reporting of tax-related assets requires the use of estimates and significant management judgment. Deferred tax assets are recorded representing future effects on income taxes for temporary differences between the bases of assets for financial reporting and tax purposes. Although management believes that current estimates for deferred tax assets are reasonable, actual results could differ from these estimates based onfor a variety of factorsreasons including change in forecasted financial condition and/or results of operations, change in income tax laws or enacted tax rates, the form, structure, and timing of asset or stock sales or dispositions, and results of audits and examinations of filed tax returns by taxing authorities. Valuation allowances against deferred tax assets are recorded when management concludes it is more likely than not such asset will not be realized in future periods. Accounting for income taxes also requires that only tax benefits for positions taken or expected to be taken on tax returns that meet the more-likely-than-not recognition threshold can be recognized or continue to be recognized. Management evaluates each position solely on the technical merits and facts and circumstances of the position, assuming that the position will be examined by a taxing authority havingthat has full knowledge of all relevant information. Significant judgment is required to determine recognition thresholds and the related amount of tax benefits to be recognized. At any period end,each period-end, and as new developments occur, management will reevaluatereevaluates its tax positions. See Note 13 -– Income Taxes under Part II, Item 8, of this report for the amount of deferred tax assets and uncertain tax positions recorded at December 31, 20122013.
Unbilled Revenue
At the end of each period, Ameren, Ameren Missouri, and Ameren Illinois project expected usage and estimate the amount of revenue to record for services that have been provided to customers but not yet billed.
Projecting customer energy usage
Estimating impacts of weather and other usage-affecting factors for the unbilled period
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 or contraction 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 under Part II, Item 8, of this report for unbilled revenue amounts.
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. Rate regulation is generally based on the recovery of historical or projected costs. As a result,
revenue increases could lag behind changing prices. Ameren Illinois elected to participate in the performance-based formula ratemaking process pursuant to the IEIMA for its electric delivery service business. Ameren Illinois’ participation in this formula ratemaking process will terminate if the average residential rate increases by more than 2.5% annually from June 2011 through May 2014. The average residential rate includes generation
service, which is outside of Ameren Illinois’ control. Ameren Illinois is required to purchase all of its power through procurement processes administered by the IPA. The cost of procured power can be affected by inflation. Within the IEIMA formula, the monthly average yields of 30-year United States treasury bonds are the basis for Ameren Illinois’ return on equity. Therefore, there is a direct correlation between the yield of United States treasury bonds, which are affected by inflation, and the earnings of Ameren Illinois’ electric distribution business. 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 business does not have regulated recovery mechanisms and is therefore dependent on market prices for power to reflect rising costs.
Ameren Missouri recovers the cost of fuel for electric generation and the cost of purchased power by adjusting rates as allowed through the FAC. Ameren Illinois recovers power supply costs from electric customers by adjusting rates through a rider mechanism to accommodate changes in power prices.
Ameren Missouri, Ameren Illinois and ATXI are affected by changes in the cost of electric transmission services. FERC regulates the rates charged and the terms and conditions for electric wholesale and unbundled retail transmission services. Because they are members of MISO, Ameren Missouri's, Ameren Illinois' and ATXI's transmission rates are calculated in
accordance with the rate formulas contained in MISO's FERC-approved tariff. Under the MISO OATT, a portion of the revenue requirement related to certain projects eligible for cost sharing areis allocated to multiple MISO pricing zones. The remaining revenue requirement is assigned to the pricing zone where the transmission assets are located. Ameren Missouri uses a rate formula that is updated in June of each year andyear. It is based on the prior-year'sprior year's cost data. The Ameren Missouri zonal rate is charged to wholesale customers in the AMMO pricing zone. However, thisThis zonal rate is not directly charged to Missouri retail customers, because the MoPSC includes transmission-related costs in setting bundled retail rates in Missouri. Ameren Illinois and ATXI have received FERC approval to use company-specific, forward-looking rate formula templates in setting their transmission rates. These forward-looking rates are updated every January. Eacheach January with forecasted information, with a subsequent reconciliation during the year after the costs are incurred, the January forecast rates are reconciled withto adjust for the actual revenue requirement.requirement and actual billed revenues, which will be used to adjust billing rates in a subsequent year. In Illinois, the AMIL pricing zone rate is charged directly to wholesale customers and alternative retail electric suppliers that serve unbundled retail load. IfFor those Ameren Illinois retail customers that do not choose an alternative retail electric supplier, the AMIL transmission rate, as well as other MISO relatedMISO-related transmission costs, is collected through the retail transmission servicesservice rider mechanism.
In our Missouri and Illinois retail natural gas utility
jurisdictions, changes in natural gas costs are generally reflected in billings to natural gas customers through PGA clauses.
Ameren and Ameren Missouri 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 natural gas pools and supply basins, and to minimize the impact to their financial statements. Ameren Missouri’s exposure to changes in market prices of natural gas for generation is mitigated by its ability to recover increasing costs via the FAC. See Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk under Part II, Item 7A, of this report for additional information.
See Note 2 -– Rate and Regulatory Matters under Part II, Item 8, of this report for additional information on the cost recovery mechanisms.
| |
| 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 or index. 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 isobjectives are 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.officers, with Ameren board of directors oversight.
Interest Rate Risk
We are exposed to market risk through changes in interest rates associated with:
long-term and short-term variable-rate debt;
fixed-rate debt;
auction-rate long-term debt; and
defined pension and postretirement benefit plans.
We manage our interest rate exposure by controlling the amount of debt instruments within our total capitalization portfolio and by monitoring the effects of market changes on interest rates. For defined pension and postretirement benefit plans, we control the duration and the 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, 20122013:
| | | | Interest Expense | | Net Income(a) | | Interest Expense | | Net Income(a) |
| Ameren | $ | 2 |
| | $ | (1 | ) | $ | 6 |
| $ | (4 | ) |
| Ameren Missouri | 2 |
| | (1 | ) | | 2 |
| | (1 | ) |
| Ameren Illinois | (b) |
| | (b) |
| | (b) |
| | (b) |
|
| |
| (a) | Calculations are based on an estimated tax rate of 37%38%, 36%38% and 40% for Ameren, Ameren Missouri and Ameren Illinois, respectively. |
Credit Risk
Credit risk represents the loss that would be recognized if counterparties should 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, 20122013.
Our rate-regulated 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, 20122013, no nonaffiliated customer represented more than 10%, in the aggregate, of our accounts receivable. Additionally, Ameren Illinois has risk associated with the purchase of receivables. The Illinois Public Utilities Act requires Ameren Illinois to establish electric utility consolidated billing and purchase of receivables services. At the option of an alternative retail electric supplier, Ameren Illinois is required to purchase the supplier's receivables relating to Ameren Illinois' delivery service customers who elected to receive power supply from the alternative retail electric supplier. When that option is selected, Ameren Illinois produces consolidated bills for the applicable retail customers reflecting charges for electric delivery service and purchased receivables. Beginning in June 2012, Ameren Illinois began purchasing trade receivables relating to the power supply of residential customers who use Marketing Company as their alternative retail electric supplier. As of December 31, 20122013, Ameren Illinois' balance of purchased accounts receivable associated with the utility consolidated billing and purchase of receivables services was $9$26 million. The risk associated with Ameren Illinois' electric and natural gas trade receivables is also mitigated by a rate adjustment mechanism that allows Ameren Illinois to recover the difference between its actual net bad debt expensewrite-offs under GAAP and the amount of net bad debt expensewrite-offs included in its base rates. Ameren Missouri and Ameren Illinois continue to monitor the impact of increasing rates on customer collections. Ameren Missouri and Ameren Illinois make adjustments to their respective allowance for doubtful accounts as deemed necessary to ensure that such allowances are
adequate to cover estimated uncollectible customer account balances.
Ameren, Ameren Missouri and Ameren Illinois and AER may have credit exposure associated with off-system or wholesale purchase and sale activity with nonaffiliated companies. At December 31, 20122013, Ameren’s and Ameren Missouri’s Ameren Illinois’ and AER's combined credit exposure to nonaffiliated trading counterparties excluding coal suppliers, deemed below investment grade either through external or internal credit evaluations, was less than $1 million, net of collateral (2011 – $48 million). At December 31, 2012, the combined credit exposures to coal suppliers, deemed below investment grade either through external or internal credit evaluations, net of collateral, were $10was less than $1 million $2 million and $8 million at Ameren, Ameren Missouri and AER, respectively (20112012 – $35 million, $33 million and $2 million, respectively)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. Monitoring 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. We estimate our
On December 2, 2013, Ameren completed the divestiture of New AER to IPH. The transaction agreement between Ameren and IPH requires Ameren, for up to 24 months after the closing of the divestiture of New AER, to maintain its financial obligations in existence as of the date of the closing under all credit exposuresupport arrangements or obligations with respect to MISO associatedNew AER and its subsidiaries. Ameren must also provide any additional credit support that may be contractually required pursuant to any of the contracts of New AER, and its subsidiaries as of the closing. IPH, New AER and its subsidiaries and Dynegy have agreed to indemnify Ameren for certain losses relating to this credit support. IPH’s indemnification obligations are secured by certain AERG and Genco assets. However, these indemnification obligations and security interests might not cover all losses incurred by Ameren in connection with the MISO Energythis credit support. In addition, Dynegy emerged from its Chapter 11 bankruptcy case on October 1, 2012, and, Operating Reserves Market to be $21 million at as of December 31, 2012 (2011 – $29 million).2013, Dynegy’s credit ratings were sub-investment grade. IPH, New AER and its subsidiaries also do not have investment grade credit ratings. Dynegy, IPH, New AER, or their subsidiaries might not be able to pay their indemnity and other obligations under the transaction agreement, Marketing Company’s note to Ameren, or Dynegy’s limited guarantee to Ameren, which could have a material adverse impact on Ameren’s results of operations, financial position, and liquidity. As of December 31, 2013, the balance of the Marketing Company note to Ameren was $18 million. As of December 31, 2013, Ameren provided $190 million in guarantees and letters of credit totaling $11 million relating to its credit support of New AER.
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 benefits at the time they are payable while also to maximizing total return on plan assets and minimizing expense volatility consistent with its tolerance for risk. Ameren delegates investment management to 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 are 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 adjust 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 will be reflected in net income, OCI, or regulatory assets. Contributions to the plans could
increase materially if we do not achieve pension and
postretirement asset portfolio investment returns equal to or in excess of our 20132014 assumed return on plan assets of 7.50%7.25% and 7.25%7.00%, respectively.
Ameren Missouri 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, 20122013, this fund was invested primarily in domestic equity securities (65%(68%) and debt securities (35%(32%). ItAs of December 31, 2013, the trust fund totaled $408494 million (20112012 – $357408 million). By maintaining a portfolio that includes long-term equity investments, Ameren Missouri 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. Ameren Missouri 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. Ameren Missouri’s exposure to equity price market risk is in large part mitigated because Ameren Missouri is currently allowed to recover its decommissioning costs, which would include unfavorable investment results, through electric rates.
Additionally, Ameren has company-owned life insurance contracts that are used to support Ameren’s deferred compensation plans. These life insurance contracts include equity and debt investments that are exposed to price fluctuations in equity markets and to changes in interest rates.
Commodity Price Risk
We are exposed to changes in market prices for power, emission allowances, coal, transportation diesel, natural gas and uranium.
Ameren’s, Ameren Missouri’s and AER's risks of changes in prices for power sales are partially hedged through sales agreements. AER also seeks 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 through 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, Ameren Missouri and AER 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 2013 through 2016:
|
| | | |
| | Net Income(a) |
Ameren(b) | $ | (10 | ) |
| Ameren Missouri | (c) |
|
| AER | (10 | ) |
| |
(a) | Calculations are based on an estimated tax rate of 37%, 36% and 42% for Ameren, Ameren Missouri and AER, respectively. |
| |
(b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
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.
Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy 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 and stop-loss limits that are intended to limit any material negative financial impacts.
We manage risks associated with changing prices of fuel for generation with techniques similar to those we use to manage risks associated with changing market prices for electricity.
Merchant Generation does not have the ability to pass higher fuel costs through to its customers for electric operations, with the exception of an immaterial percentage of the output that has been contracted with a fuel cost pass-through. Ameren Missouri has a FAC that allows Ameren Missouri to recover, through customer rates, 95% of changes in fuel, certain fuel additives, emission allowances, purchased power costs, transmission costs, and MISO costs and revenues, net of off-system revenues, greater or less than the amount set in base rates, without a traditional rate proceeding, subject to MoPSC prudency review. Ameren Missouri remains exposed to the remaining 5% of such changes. Ameren Illinois expects that purchased power procured through past IPA procurements will be in excess of requirements for the 2013 planning year due to significant switching by customers to alternative retail electric suppliers associated with municipal aggregation initiatives. The IPA has proposed and the ICC has approved that the excess purchased power will settle in the MISO market and be credited to customers taking power procured by Ameren Illinois through the IPA process. Ameren Illinois expects full recovery of its purchased power costs.
Ameren, Ameren Missouri and AER have entered into coal 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. Additionally, the type of coal burned is part of Ameren Missouri's environmental compliance strategy. Ameren Missouri has a multiyear agreement to purchase ultra-low-sulfur coal through 2017 to comply with environmental regulations. The coal contract is with a single supplier. Disruptions of the deliveries of that ultra-low-sulfur coal from the supplier could compromise Ameren Missouri's ability to operate in
compliance with emission standards. Other sources of ultra-low-sulfur coal are limited and the construction of pollution control equipment requires significant lead time to become operational. Should a temporary disruption of ultra-low-sulfur coal deliveries occur and its existing inventory of ultra-low-sulfur coal becomes fully depleted, and other sources of ultra-low-sulfur coal are not available, Ameren Missouri would use its existing emission allowances or purchase emission allowances in order to achieve compliance with environmental regulations. AER purchases coal based on expected power sales, generally through bid procedures. Therefore, AER's forward coal requirements are dependent on the volume of power sales that have been contracted.
Transportation costs for coal and natural gas can be a significant portion of fuel costs. Ameren, Ameren Missouri and AER 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 for the gas-fired generation units of Ameren, Ameren Missouri and AER 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 term of contracts. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.
In addition, coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. We use forward fuel oil contracts (both for heating and crude oil) to mitigate this market price risk as changes in these products are highly correlated to changes in diesel markets. If diesel fuel costs were to increase or decrease by $0.25 a gallon, Ameren’s fuel expense could increase or decrease by $13 million annually (Ameren Missouri – $8 million). As of December 31, 2012, Ameren had a price cap for approximately 87% of expected fuel surcharges in 2013.
In the event of a significant change in coal prices, Ameren, Ameren Missouri and AER 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, Ameren Missouri has fixed-priced, base-price-with-escalation, and market-priced agreements. It uses inventories to provide some price hedge to fulfill its Callaway energy center’s needs for uranium, conversion, and enrichment. There is no fuel reloading or planned maintenance outage scheduled for 2015. Ameren Missouri has price hedges for approximately 73% of its 2013 to 2017 nuclear fuel requirements.
Nuclear fuel market prices remain subject to an unpredictable supply-and-demand environment. Ameren Missouri 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 a base-price-with-escalation price mechanism, and may also have either a market-price-related component or market-based price re benchmarking. Ameren Missouri expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway energy center, 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.
The electric generating operations for Ameren, Ameren Missouri and AER 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 and auction process, Ameren and Ameren Missouri 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 and MISO market. The FTRs are intended to mitigate electric transmission congestion charges related to the physical constraints of the transmission system. Depending on the congestion, 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 Ameren Missouri’s and Ameren Illinois’ 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 Ameren Missouri and Ameren Illinois to pass on to retail customers prudently incurred costs for fuel, purchased power, and natural gas supply. Ameren Illinois expects that purchased power procured through past IPA procurements will be in excess of requirements for the 2013 planning year due to significant switching by customers to alternative retail electric suppliers associated with municipal aggregation initiatives. The IPA has proposed and the ICC has approved that the excess purchased power will settle in the MISO market and act as a credit to customers taking power procured by Ameren Illinois through the IPA process. Ameren Illinois expects full recovery of its purchased power costs.
Ameren Missouri’s and Ameren Illinois’ strategy is designed to reduce the effect of market fluctuations for their 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.
Ameren Missouri has a FAC that allows it to recover, through customer rates, 95% of changes in fuel, certain fuel additives, emission allowances, purchased power costs, transmission costs and revenues, and MISO costs and revenues, net of off-system sales revenues, greater or less than the amount set in base rates, without a traditional rate proceeding, subject to MoPSC prudency review. Ameren Missouri remains exposed to the remaining 5% of such changes.
Even with the FAC, Ameren Missouri enters into derivative
contracts to hedge prices of electricity, coal and coal transportation for its customers as discussed above. Ameren Missouri also attempts 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 Missouri is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices. If power prices were to decrease by 1% on unhedged economic generation for 2014 through 2018, Ameren Missouri earnings would decrease by less than $1 million, based on an 36% effective tax rate.
Ameren Illinois has a cost recovery mechanism for power purchased on behalf of its customers. Ameren Illinois does not generate earnings based on the resale of power but rather on the delivery of energy. Ameren Illinois primarily purchases power through MISO with additional procurement events administered by the IPA. The IPA has proposed and the ICC has approved
multiple energy procurement events covering portions of years through 2017. By the end of 2013, approximately 768,000 retail customers, representing 72% of Ameren Illinois' annual retail kilowatthour sales, had elected to purchase their electricity from an alternative retail electric supplier. The percentage of retail customers, especially residential customers, who elected to purchase power from a different provider than Ameren Illinois increased substantially over the last two years. For periods where existing power purchases through the IPA exceed the demand for customers taking power from Ameren Illinois, the IPA has proposed, and the ICC has approved, that excess purchases will settle in the MISO market, thus resulting in a credit to customers who take supply from Ameren Illinois fixed-price tariffs. Ameren Illinois expects full recovery of its purchased power costs.
Ameren Missouri and Ameren Illinois have PGA clauses that permit costs incurred for natural gas to be recovered directly from utility customers without a traditional rate proceeding, subject to prudency review.
The following table presents, as of December 31, 20122013, the percentages of the projected required supply of coal and coal transportation for ourAmeren Missouri's coal-fired energy centers, nuclear fuel for Ameren Missouri’s Callaway energy center, natural gas for ourAmeren Missouri's CTs and retail distribution, as appropriate, and purchased power needs offor Ameren Illinois, which does not own generation, that are price-hedged over the period 20132014 through 2017.2018. The projected required supply of these commodities could be significantly affected by changes in our assumptions for matters such asabout customer demand for our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.
| | | | 2013 | | 2014 | | 2015 – 2017 | 2014 | | 2015 | | 2016 – 2018 |
Ameren(a): | | | | | | | | | | |
| Coal | 99 | % | | 78 | % | | 60 | % | 100 | % | | 100 | % | | 70 | % |
| Coal transportation | 99 |
| | 90 |
| | 90 |
| 100 |
| | 100 |
| | 65 |
|
| Nuclear fuel | 100 |
| | 99 |
| | 49 |
| 100 |
| | 100 |
| | 66 |
|
| Natural gas for generation | 54 |
| | 2 |
| | 1 |
| 27 |
| | 22 |
| | 3 |
|
Natural gas for distribution(b) | 82 |
| | 34 |
| | 9 |
| 78 |
| | 27 |
| | 7 |
|
Purchased power for Ameren Illinois(c) | 100 |
| | 100 |
| | 50 |
| 100 |
| | 85 |
| | 20 |
|
| Ameren Missouri: | | | | | | | | | | |
| Coal | 100 | % | | 100 | % | | 94 | % | 100 | % | | 100 | % | | 70 | % |
| Coal transportation | 99 |
| | 98 |
| | 98 |
| 100 |
| | 100 |
| | 65 |
|
| Nuclear fuel | 100 |
| | 99 |
| | 49 |
| 100 |
| | 100 |
| | 66 |
|
| Natural gas for generation | 34 |
| | 9 |
| | 2 |
| 27 |
| | 22 |
| | 3 |
|
Natural gas for distribution(b) | 89 |
| | 33 |
| | 17 |
| 84 |
| | 29 |
| | 18 |
|
| Ameren Illinois: | | | | | | | | | | |
Natural gas for distribution(b) | 81 | % | | 35 | % | | 9 | % | 77 | % | | 26 | % | | 5 | % |
Purchased power(c) | 100 |
| | 100 |
| | 50 |
| 100 |
| | 85 |
| | 20 |
|
| AER: | | | | | | |
| Coal | 98 | % | | 49 | % | | 15 | % | |
| Coal transportation | 100 |
| | 80 |
| | 80 |
| |
| Natural gas for generation | 59 |
| | — |
| | — |
| |
| |
| (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 20132014 represents January 20132014 through March 2013.2014. The year 20142015 represents November 20132014 through March 2014.2015. This continues each successive year through March 2017.2018. |
| |
| (c) | Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. |
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 2013 through 2017.
|
| | | | | | | | | | | | | | | |
| Coal | | Coal Transportation |
| Fuel Expense | | Net Income(a) | | Fuel Expense | | Net Income(a) |
Ameren(b)(c) | $ | 7 |
| | $ | (4 | ) | | $ | 3 |
| | $ | (2 | ) |
Ameren Missouri(c) | (d) |
| | (d) |
| | (d) |
| | (d) |
|
| AER | 7 |
| | (4 | ) | | 3 |
| | (2 | ) |
| |
(a) | Calculations are based on an estimated tax rate of 37%, 36% and 42% for Ameren, Ameren Missouri and AER, respectively. |
| |
(b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(c) | Includes the impact of the FAC. |
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 to labor availability.
See Transmission and Supply of 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.
Commodity Supplier Risk
The use of ultra-low-sulfur coal is part of Ameren Missouri's
environmental compliance strategy. Ameren Missouri has a multiyear agreement to purchase ultra-low-sulfur coal through 2017 to comply with environmental regulations. The coal contract is with a single supplier. Disruptions of the deliveries of that ultra-
low-sulfur coal from the supplier could compromise Ameren Missouri's ability to operate in compliance with emission standards. Other sources of ultra-low-sulfur coal are limited, and the construction of pollution control equipment requires significant lead time if Ameren Missouri were to experience a temporary disruption of ultra-low-sulfur coal deliveries that caused it to exhaust its existing inventory, and if other sources of ultra-low-sulfur coal were not available, Ameren Missouri would use its existing emission allowances or purchase emission allowances to achieve compliance with environmental regulations.
Currently, the Callaway energy center uses nuclear fuel assemblies of a design fabricated by only a single supplier. That supplier is currently the only NRC-licensed supplier able to provide assemblies to the Callaway energy center. If Ameren Missouri would decide to change suppliers or change the type of fuel assembly design the Callaway energy center uses, it could take up to 3 years of analysis and licensing effort to be in a position to use nuclear fuel assemblies fabricated from a different NRC-licensed nuclear fuel supplier.
Fair Value of Contracts
We use derivatives principally to manage the risk of changes in market prices for coal, natural gas, diesel, power, and uranium. 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, 2012.2013. We use various methods to determine the fair value of our contracts. In accordance with authoritative accounting guidance for fair value with hierarchy levels, 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). See Note 8 – Fair Value Measurements under Part II, Item 8, of this report for further information regarding the methods used to determine the fair value of these contracts.
| | | | Ameren(a) | | Ameren Missouri | | Ameren Illinois | | Other(b) | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fair value of contracts at beginning of year, net | $ | (43 | ) | | $ | 18 |
| | $ | (307 | ) | | $ | 246 |
| $ | 3 |
| | $ | (204 | ) | | $ | (201 | ) |
| Contracts realized or otherwise settled during the period | 49 |
| | (27 | ) | | 320 |
| | (244 | ) | (7 | ) | | 84 |
| | 77 |
|
| Changes in fair values attributable to changes in valuation technique and assumptions | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
| Fair value of new contracts entered into during the period | 18 |
| | 17 |
| | (1 | ) | | 2 |
| 17 |
| | (4 | ) | | 13 |
|
| Other changes in fair value | (177 | ) | | (5 | ) | | (216 | ) | | 44 |
| (4 | ) | | (29 | ) | | (33 | ) |
| Fair value of contracts outstanding at end of year, net | $ | (153 | ) | | $ | 3 |
| | $ | (204 | ) | | $ | 48 |
| $ | 9 |
| | $ | (153 | ) | | $ | (144 | ) |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(b) | Includes amounts for Marketing Company, AERG, Genco and intercompany eliminations. |
The following table presents maturities of derivative contracts as of December 31, 2012,2013, 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 | 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 | ) | | $ | (8 | ) | | $ | — |
| | $ | — |
| | $ | (16 | ) | |
Level 2(a) | (60 | ) | | (39 | ) | | (1 | ) | | — |
| | (100 | ) | |
Level 3(b) | 37 |
| | (5 | ) | | (19 | ) | | (50 | ) | | (37 | ) | |
| Total | $ | (31 | ) | | $ | (52 | ) | | $ | (20 | ) | | $ | (50 | ) | | $ | (153 | ) | |
| Ameren Missouri: |
| |
| |
| |
| |
|
| |
| |
| |
| |
|
| Level 1 | $ | — |
| | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | (4 | ) | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (2 | ) |
Level 2(a) | (5 | ) | | (2 | ) | | — |
| | — |
| | (7 | ) | (1 | ) | | (4 | ) | | (1 | ) | | (1 | ) | | (7 | ) |
Level 3(b) | 12 |
| | 2 |
| | — |
| | — |
| | 14 |
| 18 |
| | — |
| | — |
| | — |
| | 18 |
|
| Total | $ | 7 |
| | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | 3 |
| $ | 15 |
| | $ | (4 | ) | | $ | (1 | ) | | $ | (1 | ) | | $ | 9 |
|
| Ameren Illinois: |
| |
| |
| |
| |
|
| |
| |
| |
| |
|
| Level 1 | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Level 2(a) | (55 | ) | | (37 | ) | | (1 | ) | | — |
| | (93 | ) | (26 | ) | | (19 | ) | | — |
| | — |
| | (45 | ) |
Level 3(b) | (20 | ) | | (21 | ) | | (20 | ) | | (50 | ) | | (111 | ) | (9 | ) | | (21 | ) | | (20 | ) | | (58 | ) | | (108 | ) |
| Total | $ | (75 | ) | | $ | (58 | ) | | $ | (21 | ) | | $ | (50 | ) | | $ | (204 | ) | $ | (35 | ) | | $ | (40 | ) | | $ | (20 | ) | | $ | (58 | ) | | $ | (153 | ) |
| Ameren: | | | | | | | | | | |
| Level 1 | | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (2 | ) |
Level 2(a) | | (27 | ) | | (23 | ) | | (1 | ) | | (1 | ) | | (52 | ) |
Level 3(b) | | 9 |
| | (21 | ) | | (20 | ) | | (58 | ) | | (90 | ) |
| Total | | $ | (20 | ) | | $ | (44 | ) | | $ | (21 | ) | | $ | (59 | ) | | $ | (144 | ) |
| |
(a) | Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed pricefixed-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, historical results, and our estimates. Level 3 also includes option contract values based on our estimates.a Black-Scholes model. |
| |
| 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, 20122013 and 2011,2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012,2013, 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. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012,2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(COSO 1992). 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
March 1, 20133, 2014
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Union Electric 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 Union Electric Company at December 31, 20122013 and 2011,2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, 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
March 3, 2014
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois 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 Ameren Illinois Company at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, 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
March 1, 2013
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
of Ameren Illinois 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 Ameren Illinois Company at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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
March 1, 20133, 2014
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (LOSS) (In millions, except per share amounts) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Operating Revenues: |
| |
| | |
| Electric | $ | 5,904 |
| | $ | 6,530 |
| | $ | 6,521 |
|
| Gas | 924 |
| | 1,001 |
| | 1,117 |
|
| Total operating revenues | 6,828 |
| | 7,531 |
| | 7,638 |
|
| Operating Expenses: |
| |
| | |
| Fuel | 1,369 |
| | 1,567 |
| | 1,323 |
|
| Purchased power | 654 |
| | 966 |
| | 1,106 |
|
| Gas purchased for resale | 472 |
| | 570 |
| | 669 |
|
| Other operations and maintenance | 1,752 |
| | 1,820 |
| | 1,821 |
|
| Impairment and other charges | 2,578 |
| | 125 |
| | 589 |
|
| Depreciation and amortization | 775 |
| | 785 |
| | 765 |
|
| Taxes other than income taxes | 468 |
| | 457 |
| | 449 |
|
| Total operating expenses | 8,068 |
| | 6,290 |
| | 6,722 |
|
| Operating Income (Loss) | (1,240 | ) | | 1,241 |
| | 916 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 71 |
| | 69 |
| | 90 |
|
| Miscellaneous expense | 37 |
| | 23 |
| | 33 |
|
| Total other income | 34 |
| | 46 |
| | 57 |
|
| Interest Charges | 448 |
| | 451 |
| | 497 |
|
| Income (Loss) Before Income Taxes | (1,654 | ) | | 836 |
| | 476 |
|
| Income Taxes (Benefit) | (680 | ) | | 310 |
| | 325 |
|
| Net Income (Loss) | (974 | ) | | 526 |
| | 151 |
|
| Less: Net Income Attributable to Noncontrolling Interest | — |
| | 7 |
| | 12 |
|
| Net Income (Loss) Attributable to Ameren Corporation | $ | (974 | ) | | $ | 519 |
| | $ | 139 |
|
| | | | | | |
| Earnings (Loss) per Common Share – Basic and Diluted | $ | (4.01 | ) | | $ | 2.15 |
| | $ | 0.58 |
|
| Dividends per Common Share | $ | 1.600 |
| | $ | 1.555 |
| | $ | 1.540 |
|
| Average Common Shares Outstanding | 242.6 |
| | 241.5 |
| | 238.8 |
|
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (LOSS) (In millions, except per share amounts) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Operating Revenues: |
| |
| | |
| Electric | $ | 4,832 |
| | $ | 4,857 |
| | $ | 5,147 |
|
| Gas | 1,006 |
| | 924 |
| | 1,001 |
|
| Total operating revenues | 5,838 |
| | 5,781 |
| | 6,148 |
|
| Operating Expenses: |
| |
| | |
| Fuel | 845 |
| | 714 |
| | 866 |
|
| Purchased power | 502 |
| | 780 |
| | 952 |
|
| Gas purchased for resale | 526 |
| | 472 |
| | 570 |
|
| Other operations and maintenance | 1,617 |
| | 1,511 |
| | 1,562 |
|
| Taum Sauk regulatory disallowance | — |
| | — |
| | 89 |
|
| Depreciation and amortization | 706 |
| | 673 |
| | 643 |
|
| Taxes other than income taxes | 458 |
| | 443 |
| | 433 |
|
| Total operating expenses | 4,654 |
| | 4,593 |
| | 5,115 |
|
| Operating Income | 1,184 |
| | 1,188 |
| | 1,033 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 69 |
| | 70 |
| | 68 |
|
| Miscellaneous expense | 26 |
| | 37 |
| | 23 |
|
| Total other income | 43 |
| | 33 |
| | 45 |
|
| Interest Charges | 398 |
| | 392 |
| | 387 |
|
| Income Before Income Taxes | 829 |
| | 829 |
| | 691 |
|
| Income Taxes | 311 |
| | 307 |
| | 254 |
|
| Income from Continuing Operations | 518 |
| | 522 |
| | 437 |
|
| Income (Loss) from Discontinued Operations, Net of Taxes (Note 16) | (223 | ) | | (1,496 | ) | | 89 |
|
| Net Income (Loss) | 295 |
| | (974 | ) | | 526 |
|
| Less: Net Income (Loss) Attributable to Noncontrolling Interests: | | | | | |
| Continuing Operations | 6 |
| | 6 |
| | 6 |
|
| Discontinued Operations | — |
| | (6 | ) | | 1 |
|
| Net Income (Loss) Attributable to Ameren Corporation: | | | | | |
| Continuing Operations | 512 |
| | 516 |
| | 431 |
|
| Discontinued Operations | (223 | ) | | (1,490 | ) | | 88 |
|
| Net Income (Loss) Attributable to Ameren Corporation | $ | 289 |
| | $ | (974 | ) | | $ | 519 |
|
| | | | | | |
| Earnings (Loss) per Common Share – Basic: | | | | | |
| Continuing Operations | $ | 2.11 |
| | $ | 2.13 |
| | $ | 1.79 |
|
| Discontinued Operations | (0.92 | ) | | (6.14 | ) | | 0.36 |
|
| Earnings (Loss) per Common Share – Basic | $ | 1.19 |
| | $ | (4.01 | ) | | $ | 2.15 |
|
| | | | | | |
| Earnings (Loss) per Common Share – Diluted: | | | | | |
| Continuing Operations | $ | 2.10 |
| | $ | 2.13 |
| | $ | 1.79 |
|
| Discontinued Operations | (0.92 | ) | | (6.14 | ) | | 0.36 |
|
| Earnings (Loss) per Common Share – Diluted | $ | 1.18 |
| | $ | (4.01 | ) | | $ | 2.15 |
|
| | | | | | |
| Dividends per Common Share | $ | 1.600 |
| | $ | 1.600 |
| | $ | 1.555 |
|
| Average Common Shares Outstanding – Basic | 242.6 |
| | 242.6 |
| | 241.5 |
|
| Average Common Shares Outstanding – Diluted | 244.5 |
| | 243.0 |
| | 242.1 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2012 | | 2011 | | 2010 |
| | | | | | |
| Net Income (Loss) | $ | (974 | ) | | $ | 526 |
| | $ | 151 |
|
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | |
| Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $12, $1, and $(1), respectively | 22 |
| | 3 |
| | (2 | ) |
| Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes (benefit) of $1, $(3), and $5, respectively | (4 | ) | | 4 |
| | (8 | ) |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $22, $(32), and $6, respectively | 32 |
| | (46 | ) | | 4 |
|
| Total other comprehensive income (loss), net of taxes | 50 |
| | (39 | ) | | (6 | ) |
| Comprehensive Income (Loss) | (924 | ) | | 487 |
| | 145 |
|
| Less: Comprehensive Income Attributable to Noncontrolling Interest | 8 |
| | 1 |
| | 10 |
|
| Comprehensive Income (Loss) Attributable to Ameren Corporation | $ | (932 | ) | | $ | 486 |
| | $ | 135 |
|
AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| | | | | | |
| Income from Continuing Operations | $ | 518 |
| | $ | 522 |
| | $ | 437 |
|
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $16, $(6), and $(14), respectively | 30 |
| | (8 | ) | | (19 | ) |
| Comprehensive Income from Continuing Operations | 548 |
| | 514 |
| | 418 |
|
| Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 6 |
| | 6 |
| | 6 |
|
| Comprehensive Income from Continuing Operations Attributable to Ameren Corporation | 542 |
| | 508 |
| | 412 |
|
| | | | | | |
| Income (Loss) from Discontinued Operations, Net of Taxes | (223 | ) | | (1,496 | ) | | 89 |
|
| Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes (Benefit) of $(10), $40, and $(14), respectively | (18 | ) | | 58 |
| | (20 | ) |
| Comprehensive Income (Loss) from Discontinued Operations | (241 | ) | | (1,438 | ) | | 69 |
|
| Less: Comprehensive Income from Discontinued Operations Attributable to Noncontrolling Interest | 1 |
| | 2 |
| | (5 | ) |
| Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation | (242 | ) | | (1,440 | ) | | 74 |
|
| | | | | | |
| Comprehensive Income (Loss) Attributable to Ameren Corporation | $ | 300 |
| | $ | (932 | ) | | $ | 486 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) | AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) | AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) |
| | | December 31, | December 31, |
| | 2012 | | 2011 | 2013 | | 2012 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 209 |
| | $ | 255 |
| $ | 30 |
| | $ | 184 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $17 and $20, respectively) | 401 |
| | 473 |
| |
| Accounts receivable – trade (less allowance for doubtful accounts of $18 and $17, respectively) | | 404 |
| | 354 |
|
| Unbilled revenue | 322 |
| | 324 |
| 304 |
| | 291 |
|
| Miscellaneous accounts and notes receivable | 95 |
| | 69 |
| 196 |
| | 71 |
|
| Materials and supplies | 704 |
| | 712 |
| 526 |
| | 570 |
|
| Mark-to-market derivative assets | 125 |
| | 115 |
| |
| Current regulatory assets | 247 |
| | 215 |
| 156 |
| | 247 |
|
| Current accumulated deferred income taxes, net | 171 |
| | 20 |
| 106 |
| | 170 |
|
| Other current assets | 95 |
| | 112 |
| 85 |
| | 98 |
|
| Assets of discontinued operations (Note 16) | | 165 |
| | 1,611 |
|
| Total current assets | 2,369 |
| | 2,295 |
| 1,972 |
| | 3,596 |
|
| Property and Plant, Net | 16,096 |
| | 18,127 |
| 16,205 |
| | 15,348 |
|
| Investments and Other Assets: | | | | | | |
| Nuclear decommissioning trust fund | 408 |
| | 357 |
| 494 |
| | 408 |
|
| Goodwill | 411 |
| | 411 |
| 411 |
| | 411 |
|
| Intangible assets | 16 |
| | 7 |
| 22 |
| | 14 |
|
| Regulatory assets | 1,786 |
| | 1,603 |
| 1,240 |
| | 1,786 |
|
| Other assets | 749 |
| | 845 |
| 698 |
| | 667 |
|
| Total investments and other assets | 3,370 |
| | 3,223 |
| 2,865 |
| | 3,286 |
|
| TOTAL ASSETS | $ | 21,835 |
| | $ | 23,645 |
| $ | 21,042 |
| | $ | 22,230 |
|
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 355 |
| | $ | 179 |
| $ | 534 |
| | $ | 355 |
|
| Short-term debt | — |
| | 148 |
| 368 |
| | — |
|
| Accounts and wages payable | 625 |
| | 693 |
| 806 |
| | 533 |
|
| Taxes accrued | 68 |
| | 65 |
| 55 |
| | 49 |
|
| Interest accrued | 99 |
| | 101 |
| 86 |
| | 89 |
|
| Customer deposits | 108 |
| | 98 |
| 105 |
| | 107 |
|
| Mark-to-market derivative liabilities | 155 |
| | 161 |
| 52 |
| | 92 |
|
| Current regulatory liabilities | 100 |
| | 133 |
| 216 |
| | 100 |
|
| Other current liabilities | 188 |
| | 207 |
| 194 |
| | 168 |
|
| Liabilities of discontinued operations (Note 16) | | 45 |
| | 1,193 |
|
| Total current liabilities | 1,698 |
| | 1,785 |
| 2,461 |
| | 2,686 |
|
| Long-term Debt, Net | 6,626 |
| | 6,677 |
| 5,504 |
| | 5,802 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 2,792 |
| | 3,315 |
| 3,166 |
| | 3,186 |
|
| Accumulated deferred investment tax credits | 72 |
| | 79 |
| 63 |
| | 70 |
|
| Regulatory liabilities | 1,589 |
| | 1,502 |
| 1,705 |
| | 1,589 |
|
| Asset retirement obligations | 445 |
| | 428 |
| 369 |
| | 349 |
|
| Pension and other postretirement benefits | 1,178 |
| | 1,344 |
| 466 |
| | 1,138 |
|
| Other deferred credits and liabilities | 668 |
| | 447 |
| 622 |
| | 643 |
|
| Total deferred credits and other liabilities | 6,744 |
| | 7,115 |
| 6,391 |
| | 6,975 |
|
| Commitments and Contingencies (Notes 2, 10, 14 and 15) |
|
| |
|
| |
| Commitments and Contingencies (Notes 2, 10, 15 and 16) | |
|
| |
|
|
| Ameren Corporation Stockholders’ Equity: | | | | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6 | 2 |
| | 2 |
| 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,616 |
| | 5,598 |
| 5,632 |
| | 5,616 |
|
| Retained earnings | 1,006 |
| | 2,369 |
| 907 |
| | 1,006 |
|
| Accumulated other comprehensive loss | (8 | ) | | (50 | ) | |
| Accumulated other comprehensive income (loss) | | 3 |
| | (8 | ) |
| Total Ameren Corporation stockholders’ equity | 6,616 |
| | 7,919 |
| 6,544 |
| | 6,616 |
|
| Noncontrolling Interests | 151 |
| | 149 |
| 142 |
| | 151 |
|
| Total equity | 6,767 |
| | 8,068 |
| 6,686 |
| | 6,767 |
|
| TOTAL LIABILITIES AND EQUITY | $ | 21,835 |
| | $ | 23,645 |
| $ | 21,042 |
| | $ | 22,230 |
|
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Cash Flows From Operating Activities: | | | | | |
| Net income (loss) | $ | (974 | ) | | $ | 526 |
| | $ | 151 |
|
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Impairment and other charges | 2,578 |
| | 125 |
| | 589 |
|
| Net gain on sales of properties | (11 | ) | | (15 | ) | | (10 | ) |
| Net mark-to-market (gain) loss on derivatives | 22 |
| | 11 |
| | (15 | ) |
| Depreciation and amortization | 735 |
| | 747 |
| | 746 |
|
| Amortization of nuclear fuel | 83 |
| | 61 |
| | 54 |
|
| Amortization of debt issuance costs and premium/discounts | 24 |
| | 21 |
| | 23 |
|
| Deferred income taxes and investment tax credits, net | (714 | ) | | 346 |
| | 410 |
|
| Allowance for equity funds used during construction | (36 | ) | | (34 | ) | | (52 | ) |
| Other | 25 |
| | — |
| | 21 |
|
| Changes in assets and liabilities: | | | | | |
| Receivables | 33 |
| | 231 |
| | (197 | ) |
| Materials and supplies | 5 |
| | (27 | ) | | 73 |
|
| Accounts and wages payable | (29 | ) | | (36 | ) | | 20 |
|
| Taxes accrued | 3 |
| | (3 | ) | | 10 |
|
| Assets, other | (10 | ) | | 76 |
| | (47 | ) |
| Liabilities, other | 71 |
| | (75 | ) | | 71 |
|
| Pension and other postretirement benefits | (23 | ) | | (102 | ) | | (5 | ) |
| Counterparty collateral, net | 46 |
| | 27 |
| | (73 | ) |
| Premiums paid on long-term debt repurchases | (138 | ) | | — |
| | — |
|
| Taum Sauk insurance recoveries, net of costs | — |
| | (1 | ) | | 54 |
|
| Net cash provided by operating activities | 1,690 |
| | 1,878 |
| | 1,823 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,240 | ) | | (1,030 | ) | | (1,042 | ) |
| Nuclear fuel expenditures | (91 | ) | | (62 | ) | | (68 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (403 | ) | | (220 | ) | | (271 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 384 |
| | 199 |
| | 256 |
|
| Proceeds from sales of properties | 22 |
| | 53 |
| | 27 |
|
| Tax grants received related to renewable energy properties | 18 |
| | — |
| | — |
|
| Other | — |
| | 12 |
| | 2 |
|
| Net cash used in investing activities | (1,310 | ) | | (1,048 | ) | | (1,096 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (382 | ) | | (375 | ) | | (368 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (8 | ) |
| Short-term debt and credit facility repayments, net | (148 | ) | | (581 | ) | | (121 | ) |
| Redemptions, repurchases, and maturities: | | | | | |
| Long-term debt | (760 | ) | | (155 | ) | | (310 | ) |
| Preferred stock | — |
| | — |
| | (52 | ) |
| Issuances: | | | | | |
| Long-term debt | 882 |
| | — |
| | — |
|
| Common stock | — |
| | 65 |
| | 80 |
|
| Capital issuance costs | (16 | ) | | — |
| | (15 | ) |
| Generator advances received for construction | 4 |
| | 5 |
| | 29 |
|
| Repayments of generator advances received for construction | — |
| | (73 | ) | | (39 | ) |
| Net cash used in financing activities | (426 | ) | | (1,120 | ) | | (804 | ) |
| Net change in cash and cash equivalents | (46 | ) | | (290 | ) | | (77 | ) |
| Cash and cash equivalents at beginning of year | 255 |
| | 545 |
| | 622 |
|
| Cash and cash equivalents at end of year | $ | 209 |
| | $ | 255 |
| | $ | 545 |
|
| | | | | | |
| Noncash financing activity – dividends on common stock | $ | (7 | ) | | — |
| | — |
|
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $30, $30, and $34 capitalized, respectively) | $ | 433 |
| | $ | 453 |
| | $ | 494 |
|
| Income taxes, net | 1 |
| | (61 | ) | | (92 | ) |
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2012 | | 2011 | | 2010 |
| 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 | 5,598 |
| | 5,520 |
| | 5,412 |
|
| Shares issued | — |
| | 65 |
| | 80 |
|
| Stock-based compensation activity | 18 |
| | 13 |
| | 14 |
|
| Regulatory recovery of prior-period common stock issuance costs | — |
| | — |
| | 14 |
|
| Other paid-in capital, end of year | 5,616 |
| | 5,598 |
| | 5,520 |
|
| Retained Earnings: | | | | | |
| Beginning of year | 2,369 |
| | 2,225 |
| | 2,455 |
|
| Net income (loss) attributable to Ameren Corporation | (974 | ) | | 519 |
| | 139 |
|
| Dividends | (389 | ) | | (375 | ) | | (368 | ) |
| Other | — |
| | — |
| | (1 | ) |
| Retained earnings, end of year | 1,006 |
| | 2,369 |
| | 2,225 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | |
| Derivative financial instruments, beginning of year | 7 |
| | — |
| | 10 |
|
| Change in derivative financial instruments | 18 |
| | 7 |
| | (10 | ) |
| Derivative financial instruments, end of year | 25 |
| | 7 |
| | — |
|
| Deferred retirement benefit costs, beginning of year | (57 | ) | | (17 | ) | | (23 | ) |
| Change in deferred retirement benefit costs | 24 |
| | (40 | ) | | 6 |
|
| Deferred retirement benefit costs, end of year | (33 | ) | | (57 | ) | | (17 | ) |
| Total accumulated other comprehensive income (loss), end of year | (8 | ) | | (50 | ) | | (17 | ) |
| Total Ameren Corporation Stockholders’ Equity | $ | 6,616 |
| | $ | 7,919 |
| | $ | 7,730 |
|
| Noncontrolling Interests: | | | | | |
| Beginning of year | 149 |
| | 154 |
| | 204 |
|
| Net income attributable to noncontrolling interest holders | — |
| | 7 |
| | 12 |
|
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (8 | ) |
| Redemptions of preferred stock | — |
| | — |
| | (52 | ) |
| Other | 8 |
| | (6 | ) | | (2 | ) |
| Noncontrolling interests, end of year | 151 |
| | 149 |
| | 154 |
|
| Total Equity | $ | 6,767 |
| | $ | 8,068 |
| | $ | 7,884 |
|
| | | | | | |
| | | | | | |
| Common stock shares at beginning of year | 242.6 |
| | 240.4 |
| | 237.4 |
|
| Shares issued | — |
| | 2.2 |
| | 3.0 |
|
| Common stock shares at end of year | 242.6 |
| | 242.6 |
| | 240.4 |
|
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Cash Flows From Operating Activities: | | | | | |
| Net income (loss) | $ | 295 |
| | $ | (974 | ) | | $ | 526 |
|
| (Income) loss from discontinued operations, net of tax | 223 |
| | 1,496 |
| | (89 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 666 |
| | 633 |
| | 602 |
|
| Amortization of nuclear fuel | 71 |
| | 83 |
| | 61 |
|
| Amortization of debt issuance costs and premium/discounts | 24 |
| | 20 |
| | 16 |
|
| Deferred income taxes and investment tax credits, net | 410 |
| | 257 |
| | 262 |
|
| Allowance for equity funds used during construction | (37 | ) | | (36 | ) | | (34 | ) |
| Stock-based compensation costs | 27 |
| | 29 |
| | 17 |
|
| Taum Sauk regulatory disallowance | — |
| | — |
| | 89 |
|
| Other | 23 |
| | (7 | ) | | 1 |
|
| Changes in assets and liabilities: | | | | | |
| Receivables | (60 | ) | | 30 |
| | 200 |
|
| Materials and supplies | 60 |
| | (28 | ) | | (29 | ) |
| Accounts and wages payable | 81 |
| | (34 | ) | | (28 | ) |
| Taxes accrued | (195 | ) | | (4 | ) | | (5 | ) |
| Assets, other | 2 |
| | (6 | ) | | 59 |
|
| Liabilities, other | 33 |
| | 65 |
| | (85 | ) |
| Pension and other postretirement benefits | (28 | ) | | (23 | ) | | (100 | ) |
| Counterparty collateral, net | 41 |
| | 41 |
| | 36 |
|
| Premiums paid on long-term debt repurchases | — |
| | (138 | ) | | — |
|
| Net cash provided by operating activities – continuing operations | 1,636 |
| | 1,404 |
| | 1,499 |
|
| Net cash provided by operating activities – discontinued operations | 57 |
| | 286 |
| | 379 |
|
| Net cash provided by operating activities | 1,693 |
| | 1,690 |
| | 1,878 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (1,379 | ) | | (1,063 | ) | | (881 | ) |
| Nuclear fuel expenditures | (45 | ) | | (91 | ) | | (62 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (214 | ) | | (403 | ) | | (220 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 196 |
| | 384 |
| | 199 |
|
| Tax grants received related to renewable energy properties | — |
| | 18 |
| | — |
|
| Other | 2 |
| | 2 |
| | 15 |
|
| Net cash used in investing activities – continuing operations | (1,440 | ) | | (1,153 | ) | | (949 | ) |
| Net cash used in investing activities – discontinued operations | (283 | ) | | (157 | ) | | (99 | ) |
| Net cash used in investing activities | (1,723 | ) | | (1,310 | ) | | (1,048 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (388 | ) | | (382 | ) | | (375 | ) |
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Short-term debt and credit facility repayments, net | 368 |
| | (148 | ) | | (481 | ) |
| Redemptions, repurchases, and maturities of long-term debt | (399 | ) | | (760 | ) | | (155 | ) |
| Issuances: | | | | | |
| Long-term debt | 278 |
| | 882 |
| | — |
|
| Common stock | — |
| | — |
| | 65 |
|
| Capital issuance costs | (2 | ) | | (16 | ) | | — |
|
| Advances received for construction | 1 |
| | 4 |
| | 5 |
|
| Repayments of advances received for construction | (1 | ) | | — |
| | (73 | ) |
| Net cash used in financing activities – continuing operations | (149 | ) | | (426 | ) | | (1,020 | ) |
| Net cash used in financing activities – discontinued operations | — |
| | — |
| | (100 | ) |
| Net cash used in financing activities | (149 | ) | | (426 | ) | | (1,120 | ) |
| Net change in cash and cash equivalents | (179 | ) | | (46 | ) | | (290 | ) |
| Cash and cash equivalents at beginning of year | 209 |
| | 255 |
| | 545 |
|
| Cash and cash equivalents at end of year | 30 |
| | 209 |
| | 255 |
|
| Less: cash and cash equivalents at end of year – discontinued operations | — |
| | 25 |
| | 7 |
|
| Cash and cash equivalents at end of year – continuing operations | $ | 30 |
| | $ | 184 |
| | $ | 248 |
|
| | | | | | |
| Noncash financing activity – dividends on common stock | $ | — |
| | $ | (7 | ) | | $ | — |
|
The accompanying notes are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2012 |
| 2011 | | 2010 |
| Operating Revenues: |
|
|
| | |
| Electric | $ | 3,132 |
|
| $ | 3,222 |
| | $ | 3,030 |
|
| Gas | 139 |
|
| 156 |
| | 166 |
|
| Other | 1 |
|
| 5 |
| | 1 |
|
| Total operating revenues | 3,272 |
|
| 3,383 |
| | 3,197 |
|
| Operating Expenses: |
|
|
| | |
| Fuel | 714 |
|
| 866 |
| | 635 |
|
| Purchased power | 78 |
|
| 104 |
| | 162 |
|
| Gas purchased for resale | 64 |
| | 77 |
| | 91 |
|
| Other operations and maintenance | 827 |
| | 934 |
| | 931 |
|
| Loss from regulatory disallowance | — |
| | 89 |
| | — |
|
| Depreciation and amortization | 440 |
| | 408 |
| | 382 |
|
| Taxes other than income taxes | 304 |
| | 296 |
| | 285 |
|
| Total operating expenses | 2,427 |
| | 2,774 |
| | 2,486 |
|
| Operating Income | 845 |
| | 609 |
| | 711 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 63 |
| | 61 |
| | 83 |
|
| Miscellaneous expense | 14 |
| | 10 |
| | 13 |
|
| Total other income | 49 |
| | 51 |
| | 70 |
|
| Interest Charges | 223 |
| | 209 |
| | 213 |
|
| Income Before Income Taxes | 671 |
| | 451 |
| | 568 |
|
| Income Taxes | 252 |
| | 161 |
| | 199 |
|
| Net Income | 419 |
| | 290 |
| | 369 |
|
| Other Comprehensive Income | — |
| | — |
| | — |
|
| Comprehensive Income | $ | 419 |
| | $ | 290 |
| | $ | 369 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 419 |
| | $ | 290 |
| | $ | 369 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 5 |
|
| Net Income Available to Common Stockholder | $ | 416 |
| | $ | 287 |
| | $ | 364 |
|
AMEREN CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2013 | | 2012 | | 2011 |
| 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 | 5,616 |
| | 5,598 |
| | 5,520 |
|
| Shares issued | — |
| | — |
| | 65 |
|
| Stock-based compensation activity | 16 |
| | 18 |
| | 13 |
|
| Other paid-in capital, end of year | 5,632 |
| | 5,616 |
| | 5,598 |
|
| Retained Earnings: | | | | | |
| Beginning of year | 1,006 |
| | 2,369 |
| | 2,225 |
|
| Net income (loss) attributable to Ameren Corporation | 289 |
| | (974 | ) | | 519 |
|
| Dividends | (388 | ) | | (389 | ) | | (375 | ) |
| Retained earnings, end of year | 907 |
| | 1,006 |
| | 2,369 |
|
| Accumulated Other Comprehensive Income (Loss): | | | | | |
| Derivative financial instruments, beginning of year | 25 |
| | 7 |
| | — |
|
| Change in derivative financial instruments | (21 | ) | | 18 |
| | 7 |
|
| Divestiture of derivative financial instruments (Note 16) | (4 | ) | | — |
| | — |
|
| Derivative financial instruments, end of year | — |
| | 25 |
| | 7 |
|
| Deferred retirement benefit costs, beginning of year | (33 | ) | | (57 | ) | | (17 | ) |
| Change in deferred retirement benefit costs | 29 |
| | 24 |
| | (40 | ) |
| Divestiture of deferred retirement benefit costs (Note 16) | 7 |
| | — |
| | — |
|
| Deferred retirement benefit costs, end of year | 3 |
| | (33 | ) | | (57 | ) |
| Total accumulated other comprehensive income (loss), end of year | 3 |
| | (8 | ) | | (50 | ) |
| Total Ameren Corporation Stockholders’ Equity | $ | 6,544 |
| | $ | 6,616 |
| | $ | 7,919 |
|
| Noncontrolling Interests: | | | | | |
| Beginning of year | 151 |
| | 149 |
| | 154 |
|
| Net income attributable to noncontrolling interest holders | 6 |
| | — |
| | 7 |
|
| Dividends paid to noncontrolling interest holders | (6 | ) | | (6 | ) | | (6 | ) |
| Divestiture of noncontrolling interest (Note 16) | (9 | ) | | — |
| | — |
|
| Other | — |
| | 8 |
| | (6 | ) |
| Noncontrolling interests, end of year | 142 |
| | 151 |
| | 149 |
|
| Total Equity | $ | 6,686 |
| | $ | 6,767 |
| | $ | 8,068 |
|
| | | | | | |
| | | | | | |
| Common stock shares at beginning of year | 242.6 |
| | 242.6 |
| | 240.4 |
|
| Shares issued | — |
| | — |
| | 2.2 |
|
| Common stock shares at end of year | 242.6 |
| | 242.6 |
| | 242.6 |
|
The accompanying notes are an integral part of these consolidated financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF INCOME AND COMPREHENSIVE INCOME (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 |
| 2012 | | 2011 |
| Operating Revenues: |
|
|
| | |
| Electric | $ | 3,379 |
|
| $ | 3,132 |
| | $ | 3,222 |
|
| Gas | 161 |
|
| 139 |
| | 156 |
|
| Other | 1 |
|
| 1 |
| | 5 |
|
| Total operating revenues | 3,541 |
|
| 3,272 |
| | 3,383 |
|
| Operating Expenses: |
|
|
| | |
| Fuel | 845 |
|
| 714 |
| | 866 |
|
| Purchased power | 127 |
|
| 78 |
| | 104 |
|
| Gas purchased for resale | 78 |
| | 64 |
| | 77 |
|
| Other operations and maintenance | 915 |
| | 827 |
| | 934 |
|
| Taum Sauk regulatory disallowance | — |
| | — |
| | 89 |
|
| Depreciation and amortization | 454 |
| | 440 |
| | 408 |
|
| Taxes other than income taxes | 319 |
| | 304 |
| | 296 |
|
| Total operating expenses | 2,738 |
| | 2,427 |
| | 2,774 |
|
| Operating Income | 803 |
| | 845 |
| | 609 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 58 |
| | 63 |
| | 61 |
|
| Miscellaneous expense | 11 |
| | 14 |
| | 10 |
|
| Total other income | 47 |
| | 49 |
| | 51 |
|
| Interest Charges | 210 |
| | 223 |
| | 209 |
|
| Income Before Income Taxes | 640 |
| | 671 |
| | 451 |
|
| Income Taxes | 242 |
| | 252 |
| | 161 |
|
| Net Income | 398 |
| | 419 |
| | 290 |
|
| Other Comprehensive Income | — |
| | — |
| | — |
|
| Comprehensive Income | $ | 398 |
| | $ | 419 |
| | $ | 290 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 398 |
| | $ | 419 |
| | $ | 290 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Stockholder | $ | 395 |
| | $ | 416 |
| | $ | 287 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY BALANCE SHEET (In millions, except per share amounts) | |
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) BALANCE SHEET (In millions, except per share amounts) | | UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) BALANCE SHEET (In millions, except per share amounts) |
| | | December 31, | December 31, |
| | 2012 | | 2011 | 2013 | | 2012 |
| ASSETS | | | | | | |
| Current Assets: | | | | | | |
| Cash and cash equivalents | $ | 148 |
| | $ | 201 |
| $ | 1 |
| | $ | 148 |
|
| Advances to money pool | 24 |
| | — |
| — |
| | 24 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $5 and $7, respectively) | 161 |
| | 212 |
| |
| Accounts receivable – trade (less allowance for doubtful accounts of $5 and $5, respectively) | | 191 |
| | 161 |
|
| Accounts receivable – affiliates | 4 |
| | 1 |
| 1 |
| | 4 |
|
| Unbilled revenue | 145 |
| | 139 |
| 168 |
| | 145 |
|
| Miscellaneous accounts and notes receivable | 48 |
| | 42 |
| 57 |
| | 48 |
|
| Materials and supplies | 397 |
| | 348 |
| 352 |
| | 397 |
|
| Current regulatory assets | 163 |
| | 109 |
| 118 |
| | 163 |
|
| Other current assets | 69 |
| | 82 |
| 71 |
| | 69 |
|
| Total current assets | 1,159 |
| | 1,134 |
| 959 |
| | 1,159 |
|
| Property and Plant, Net | 10,161 |
| | 9,958 |
| 10,452 |
| | 10,161 |
|
| Investments and Other Assets: | | | | | | |
| Nuclear decommissioning trust fund | 408 |
| | 357 |
| 494 |
| | 408 |
|
| Intangible assets | 14 |
| | 7 |
| 22 |
| | 14 |
|
| Regulatory assets | 852 |
| | 855 |
| 534 |
| | 852 |
|
| Other assets | 449 |
| | 446 |
| 443 |
| | 449 |
|
| Total investments and other assets | 1,723 |
| | 1,665 |
| 1,493 |
| | 1,723 |
|
| TOTAL ASSETS | $ | 13,043 |
| | $ | 12,757 |
| $ | 12,904 |
| | $ | 13,043 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | |
| Current Liabilities: | | | | | | |
| Current maturities of long-term debt | $ | 205 |
| | $ | 178 |
| $ | 109 |
| | $ | 205 |
|
| Borrowings from money pool | | 105 |
| | — |
|
| Accounts and wages payable | 345 |
| | 414 |
| 387 |
| | 345 |
|
| Accounts payable – affiliates | 66 |
| | 73 |
| 30 |
| | 66 |
|
| Taxes accrued | 28 |
| | 74 |
| 220 |
| | 28 |
|
| Interest accrued | 60 |
| | 62 |
| 57 |
| | 60 |
|
| Current regulatory liabilities | 18 |
| | 57 |
| 57 |
| | 18 |
|
| Other current liabilities | 77 |
| | 84 |
| 82 |
| | 77 |
|
| Total current liabilities | 799 |
| | 942 |
| 1,047 |
| | 799 |
|
| Long-term Debt, Net | 3,801 |
| | 3,772 |
| 3,648 |
| | 3,801 |
|
| Deferred Credits and Other Liabilities: | | | | | | |
| Accumulated deferred income taxes, net | 2,443 |
| | 2,132 |
| 2,509 |
| | 2,443 |
|
| Accumulated deferred investment tax credits | 64 |
| | 70 |
| 59 |
| | 64 |
|
| Regulatory liabilities | 917 |
| | 836 |
| 1,041 |
| | 917 |
|
| Asset retirement obligations | 346 |
| | 328 |
| 366 |
| | 346 |
|
| Pension and other postretirement benefits | 461 |
| | 491 |
| 189 |
| | 461 |
|
| Other deferred credits and liabilities | 158 |
| | 149 |
| 52 |
| | 158 |
|
| Total deferred credits and other liabilities | 4,389 |
| | 4,006 |
| 4,216 |
| | 4,389 |
|
| 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 | 1,556 |
| | 1,555 |
| 1,560 |
| | 1,556 |
|
| Preferred stock not subject to mandatory redemption | 80 |
| | 80 |
| 80 |
| | 80 |
|
| Retained earnings | 1,907 |
| | 1,891 |
| 1,842 |
| | 1,907 |
|
| Total stockholders’ equity | 4,054 |
| | 4,037 |
| 3,993 |
| | 4,054 |
|
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 13,043 |
| | $ | 12,757 |
| $ | 12,904 |
| | $ | 13,043 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 398 |
| | $ | 419 |
| | $ | 290 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Taum Sauk regulatory disallowance | — |
| | — |
| | 89 |
|
| Depreciation and amortization | 419 |
| | 407 |
| | 377 |
|
| Amortization of nuclear fuel | 71 |
| | 83 |
| | 61 |
|
| FAC prudence review charges | 26 |
| | — |
| | 18 |
|
| Amortization of debt issuance costs and premium/discounts | 7 |
| | 6 |
| | 6 |
|
| Deferred income taxes and investment tax credits, net | 65 |
| | 287 |
| | 155 |
|
| Allowance for equity funds used during construction | (31 | ) | | (31 | ) | | (30 | ) |
| Other | 1 |
| | 8 |
| | (8 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | (59 | ) | | 27 |
| | 66 |
|
| Materials and supplies | 45 |
| | (48 | ) | | (7 | ) |
| Accounts and wages payable | 42 |
| | (27 | ) | | 12 |
|
| Taxes accrued | 100 |
| | (46 | ) | | (6 | ) |
| Assets, other | 47 |
| | (35 | ) | | 79 |
|
| Liabilities, other | 10 |
| | 14 |
| | (48 | ) |
| Pension and other postretirement benefits | 2 |
| | 2 |
| | 2 |
|
| Premiums paid on long-term debt repurchases | �� |
| | (62 | ) | | — |
|
| Net cash provided by operating activities | 1,143 |
| | 1,004 |
| | 1,056 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (648 | ) | | (595 | ) | | (550 | ) |
| Nuclear fuel expenditures | (45 | ) | | (91 | ) | | (62 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (214 | ) | | (403 | ) | | (220 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 196 |
| | 384 |
| | 199 |
|
| Money pool advances, net | 24 |
| | (24 | ) | | — |
|
| Tax grants received related to renewable energy properties | — |
| | 18 |
| | — |
|
| Other | — |
| | 8 |
| | 6 |
|
| Net cash used in investing activities | (687 | ) | | (703 | ) | | (627 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (460 | ) | | (400 | ) | | (403 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Money pool borrowings, net | 105 |
| | — |
| | — |
|
| Redemptions, repurchases, and maturities of long-term debt | (249 | ) | | (427 | ) | | (5 | ) |
| Issuances of long-term debt | — |
| | 482 |
| | — |
|
| Capital issuance costs | — |
| | (7 | ) | | — |
|
| Capital contribution from parent | 4 |
| | 1 |
| | — |
|
| Repayments of advances received for construction | — |
| | — |
| | (19 | ) |
| Net cash used in financing activities | (603 | ) | | (354 | ) | | (430 | ) |
| Net change in cash and cash equivalents | (147 | ) | | (53 | ) | | (1 | ) |
| Cash and cash equivalents at beginning of year | 148 |
| | 201 |
| | 202 |
|
| Cash and cash equivalents at end of year | $ | 1 |
| | $ | 148 |
| | $ | 201 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $16, $15, and $25 capitalized, respectively) | $ | 212 |
| | $ | 220 |
| | $ | 210 |
|
| Income taxes, net | 86 |
| | (3 | ) | | 9 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY (d/b/a AMEREN MISSOURI) STATEMENT OF STOCKHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2013 | | 2012 | | 2011 |
| Common Stock | $ | 511 |
| | $ | 511 |
| | $ | 511 |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 1,556 |
| | 1,555 |
| | 1,555 |
|
| Capital contribution from parent | 4 |
| | 1 |
| | — |
|
| Other paid-in capital, end of year | 1,560 |
| | 1,556 |
| | 1,555 |
|
| | | | | | |
| Preferred Stock Not Subject to Mandatory Redemption | 80 |
| | 80 |
| | 80 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 1,907 |
| | 1,891 |
| | 2,007 |
|
| Net income | 398 |
| | 419 |
| | 290 |
|
| Common stock dividends | (460 | ) | | (400 | ) | | (403 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 1,842 |
| | 1,907 |
| | 1,891 |
|
| | | | | | |
| Total Stockholders’ Equity | $ | 3,993 |
| | $ | 4,054 |
| | $ | 4,037 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 419 |
| | $ | 290 |
| | $ | 369 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Loss from regulatory disallowance | — |
| | 89 |
| | — |
|
| Gain on sale of properties | — |
| | (3 | ) | | (5 | ) |
| Net mark-to-market (gain) loss on derivatives | — |
| | 1 |
| | (1 | ) |
| Depreciation and amortization | 407 |
| | 377 |
| | 355 |
|
| Amortization of nuclear fuel | 83 |
| | 61 |
| | 54 |
|
| Amortization of debt issuance costs and premium/discounts | 6 |
| | 6 |
| | 4 |
|
| Deferred income taxes and investment tax credits, net | 287 |
| | 155 |
| | 292 |
|
| Allowance for equity funds used during construction | (31 | ) | | (30 | ) | | (50 | ) |
| Other | 8 |
| | (6 | ) | | 10 |
|
| Changes in assets and liabilities: | | | | | |
| Receivables | 27 |
| | 66 |
| | (122 | ) |
| Materials and supplies | (48 | ) | | (7 | ) | | 7 |
|
| Accounts and wages payable | (27 | ) | | 13 |
| | (24 | ) |
| Taxes accrued | (46 | ) | | (6 | ) | | 55 |
|
| Assets, other | (35 | ) | | 79 |
| | (101 | ) |
| Liabilities, other | 14 |
| | (30 | ) | | 75 |
|
| Pension and other postretirement benefits | 2 |
| | 2 |
| | (3 | ) |
| Taum Sauk insurance recoveries, net of costs | — |
| | (1 | ) | | 54 |
|
| Premiums paid on long-term debt repurchases | (62 | ) | | — |
| | — |
|
| Net cash provided by operating activities | 1,004 |
| | 1,056 |
| | 969 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (595 | ) | | (550 | ) | | (624 | ) |
| Nuclear fuel expenditures | (91 | ) | | (62 | ) | | (68 | ) |
| Purchases of securities – nuclear decommissioning trust fund | (403 | ) | | (220 | ) | | (271 | ) |
| Sales and maturities of securities – nuclear decommissioning trust fund | 384 |
| | 199 |
| | 256 |
|
| Money pool advances, net | (24 | ) | | — |
| | — |
|
| Tax grants received related to renewable energy properties | 18 |
| | — |
| | — |
|
| Other | 8 |
| | 6 |
| | 7 |
|
| Net cash used in investing activities | (703 | ) | | (627 | ) | | (700 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (400 | ) | | (403 | ) | | (235 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (5 | ) |
| Redemptions, repurchases, and maturities: | | | | | |
| Long-term debt | (427 | ) | | (5 | ) | | (70 | ) |
| Preferred stock | — |
| | — |
| | (33 | ) |
| Issuances of long-term debt | 482 |
| | — |
| | — |
|
| Capital issuance costs | (7 | ) | | — |
| | (4 | ) |
| Capital contribution from parent | 1 |
| | — |
| | — |
|
| Generator advances received for construction | — |
| | — |
| | 13 |
|
| Repayments of generator advances received for construction | — |
| | (19 | ) | | — |
|
| Net cash used in financing activities | (354 | ) | | (430 | ) | | (334 | ) |
| Net change in cash and cash equivalents | (53 | ) | | (1 | ) | | (65 | ) |
| Cash and cash equivalents at beginning of year | 201 |
| | 202 |
| | 267 |
|
| Cash and cash equivalents at end of year | $ | 148 |
| | $ | 201 |
| | $ | 202 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $15, $25, and $26 capitalized, respectively) | $ | 220 |
| | $ | 210 |
| | $ | 213 |
|
| Income taxes, net | (3 | ) | | 9 |
| | (106 | ) |
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
UNION ELECTRIC COMPANY STATEMENT OF STOCKHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2012 | | 2011 | | 2010 |
| Common Stock | $ | 511 |
| | $ | 511 |
| | $ | 511 |
|
| Other Paid-in Capital: | | | | | |
| Beginning of year | 1,555 |
| | 1,555 |
| | 1,555 |
|
| Capital contribution from parent | 1 |
| | — |
| | — |
|
| Other paid-in capital, end of year | 1,556 |
| | 1,555 |
| | 1,555 |
|
| Preferred Stock Not Subject to Mandatory Redemption: | | | | | |
| Beginning balance | 80 |
| | 80 |
| | 113 |
|
| Redemptions | — |
| | — |
| | (33 | ) |
| Preferred stock not subject to mandatory redemption, end of year | 80 |
| | 80 |
| | 80 |
|
| Retained Earnings: | | | | | |
| Beginning of year | 1,891 |
| | 2,007 |
| | 1,878 |
|
| Net income | 419 |
| | 290 |
| | 369 |
|
| Common stock dividends | (400 | ) | | (403 | ) | | (235 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (5 | ) |
| Retained earnings, end of year | 1,907 |
| | 1,891 |
| | 2,007 |
|
| Total Stockholders’ Equity | $ | 4,054 |
| | $ | 4,037 |
| | $ | 4,153 |
|
The accompanying notes as they relate to Ameren Missouri are an integral part of these financial statements.
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS)
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
(In millions)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Operating Revenues: | | | | | |
| Electric | $ | 1,461 |
| | $ | 1,739 |
| | $ | 1,940 |
|
| Gas | 847 |
| | 786 |
| | 846 |
|
| Other | 3 |
| | — |
| | 1 |
|
| Total operating revenues | 2,311 |
| | 2,525 |
| | 2,787 |
|
| Operating Expenses: | | | | | |
| Purchased power | 380 |
| | 705 |
| | 853 |
|
| Gas purchased for resale | 448 |
| | 408 |
| | 492 |
|
| Other operations and maintenance | 693 |
| | 684 |
| | 640 |
|
| Depreciation and amortization | 243 |
| | 221 |
| | 215 |
|
| Taxes other than income taxes | 132 |
| | 130 |
| | 129 |
|
| Total operating expenses | 1,896 |
| | 2,148 |
| | 2,329 |
|
| Operating Income | 415 |
| | 377 |
| | 458 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 10 |
| | 7 |
| | 7 |
|
| Miscellaneous expense | 9 |
| | 17 |
| | 6 |
|
| Total other income (expense) | 1 |
| | (10 | ) | | 1 |
|
| Interest Charges | 143 |
| | 129 |
| | 136 |
|
| Income Before Income Taxes | 273 |
| | 238 |
| | 323 |
|
| Income Taxes | 110 |
| | 94 |
| | 127 |
|
| Net Income | 163 |
| | 144 |
| | 196 |
|
| Other Comprehensive Loss, Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of income tax benefit of $(2), $(2) and $(2), respectively | (3 | ) | | (3 | ) | | (3 | ) |
| Comprehensive Income | $ | 160 |
| | $ | 141 |
| | $ | 193 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 163 |
| | $ | 144 |
| | $ | 196 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 3 |
|
| Net Income Available to Common Stockholder | $ | 160 |
| | $ | 141 |
| | $ | 193 |
|
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Operating Revenues: |
| |
| | |
| Electric | $ | 1,739 |
| | $ | 1,940 |
| | $ | 2,061 |
|
| Gas | 786 |
| | 846 |
| | 953 |
|
| Other | — |
| | 1 |
| | — |
|
| Total operating revenues | 2,525 |
| | 2,787 |
| | 3,014 |
|
| Operating Expenses: |
| |
| | |
| Purchased power | 705 |
| | 853 |
| | 965 |
|
| Gas purchased for resale | 408 |
| | 492 |
| | 578 |
|
| Other operations and maintenance | 684 |
| | 640 |
| | 635 |
|
| Depreciation and amortization | 221 |
| | 215 |
| | 210 |
|
| Taxes other than income taxes | 130 |
| | 129 |
| | 128 |
|
| Total operating expenses | 2,148 |
| | 2,329 |
| | 2,516 |
|
| Operating Income | 377 |
| | 458 |
| | 498 |
|
| Other Income and Expenses: | | | | | |
| Miscellaneous income | 7 |
| | 7 |
| | 7 |
|
| Miscellaneous expense | 17 |
| | 6 |
| | 13 |
|
| Total other income (expense) | (10 | ) | | 1 |
| | (6 | ) |
| Interest Charges | 129 |
| | 136 |
| | 143 |
|
| Income Before Income Taxes | 238 |
| | 323 |
| | 349 |
|
| Income Taxes | 94 |
| | 127 |
| | 137 |
|
| Income from Continuing Operations | 144 |
| | 196 |
| | 212 |
|
| Income from Discontinued Operations, net of tax | — |
| | — |
| | 40 |
|
| Net Income | 144 |
| | 196 |
| | 252 |
|
| Other Comprehensive Loss, Net of Taxes: | | | | | |
| Pension and other postretirement benefit plan activity, net of | | | | | |
| income tax benefit of $(2), $(2) and $(2), respectively | (3 | ) | | (3 | ) | | (4 | ) |
| Other comprehensive income from discontinued operations | — |
| | — |
| | (1 | ) |
| Comprehensive Income | $ | 141 |
| | $ | 193 |
| | $ | 247 |
|
| | | | | | |
| | | | | | |
| Net Income | $ | 144 |
| | $ | 196 |
| | $ | 252 |
|
| Preferred Stock Dividends | 3 |
| | 3 |
| | 4 |
|
| Net Income Available to Common Stockholder | $ | 141 |
| | $ | 193 |
| | $ | 248 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) BALANCE SHEET (In millions) |
| | | | | | | |
| | December 31, |
| | 2013 | | 2012 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | 1 |
| | $ | — |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $13 and $12, respectively) | 201 |
| | 182 |
|
| Accounts receivable – affiliates | — |
| | 10 |
|
| Unbilled revenue | 135 |
| | 146 |
|
| Miscellaneous accounts receivable | 13 |
| | 22 |
|
| Materials and supplies | 174 |
| | 173 |
|
| Current regulatory assets | 38 |
| | 84 |
|
| Current accumulated deferred income taxes, net | 45 |
| | 85 |
|
| Other current assets | 26 |
| | 47 |
|
| Total current assets | 633 |
| | 749 |
|
| Property and Plant, Net | 5,589 |
| | 5,052 |
|
| Investments and Other Assets: | | | |
| Tax receivable – Genco | — |
| | 39 |
|
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 701 |
| | 934 |
|
| Other assets | 120 |
| | 97 |
|
| Total investments and other assets | 1,232 |
| | 1,481 |
|
| TOTAL ASSETS | $ | 7,454 |
| | $ | 7,282 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | — |
| | $ | 150 |
|
| Borrowings from money pool | 56 |
| | 24 |
|
| Accounts and wages payable | 243 |
| | 146 |
|
| Accounts payable – affiliates | 18 |
| | 86 |
|
| Taxes accrued | 23 |
| | 18 |
|
| Customer deposits | 79 |
| | 85 |
|
| Mark-to-market derivative liabilities | 36 |
| | 77 |
|
| Current environmental remediation | 43 |
| | 37 |
|
| Current regulatory liabilities | 159 |
| | 82 |
|
| Other current liabilities | 114 |
| | 92 |
|
| Total current liabilities | 771 |
| | 797 |
|
| Long-term Debt, Net | 1,856 |
| | 1,577 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 1,116 |
| | 1,025 |
|
| Accumulated deferred investment tax credits | 4 |
| | 5 |
|
| Regulatory liabilities | 664 |
| | 672 |
|
| Pension and other postretirement benefits | 197 |
| | 406 |
|
| Environmental remediation | 232 |
| | 216 |
|
| Other deferred credits and liabilities | 166 |
| | 183 |
|
| Total deferred credits and other liabilities | 2,379 |
| | 2,507 |
|
| 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 | 1,965 |
| | 1,965 |
|
| Preferred stock not subject to mandatory redemption | 62 |
| | 62 |
|
| Retained earnings | 410 |
| | 360 |
|
| Accumulated other comprehensive income | 11 |
| | 14 |
|
| Total stockholders’ equity | 2,448 |
| | 2,401 |
|
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 7,454 |
| | $ | 7,282 |
|
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
AMEREN ILLINOIS COMPANY BALANCE SHEET (In millions) |
| | | | | | | |
| | December 31, |
| | 2012 | | 2011 |
| ASSETS | | | |
| Current Assets: | | | |
| Cash and cash equivalents | $ | — |
| | $ | 21 |
|
| Accounts receivable – trade (less allowance for doubtful accounts of $12 and $13, respectively) | 182 |
| | 201 |
|
| Accounts receivable – affiliates | 10 |
| | 15 |
|
| Unbilled revenue | 146 |
| | 146 |
|
| Miscellaneous accounts receivable | 22 |
| | 6 |
|
| Materials and supplies | 173 |
| | 199 |
|
| Current regulatory assets | 84 |
| | 306 |
|
| Current accumulated deferred income taxes, net | 85 |
| | 58 |
|
| Other current assets | 47 |
| | 65 |
|
| Total current assets | 749 |
| | 1,017 |
|
| Property and Plant, Net | 5,052 |
| | 4,770 |
|
| Investments and Other Assets: | | | |
| Tax receivable – Genco | 39 |
| | 56 |
|
| Goodwill | 411 |
| | 411 |
|
| Regulatory assets | 934 |
| | 748 |
|
| Other assets | 97 |
| | 211 |
|
| Total investments and other assets | 1,481 |
| | 1,426 |
|
| TOTAL ASSETS | $ | 7,282 |
| | $ | 7,213 |
|
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
| Current Liabilities: | | | |
| Current maturities of long-term debt | $ | 150 |
| | $ | 1 |
|
| Borrowings from money pool | 24 |
| | — |
|
| Accounts and wages payable | 146 |
| | 133 |
|
| Accounts payable – affiliates | 86 |
| | 103 |
|
| Taxes accrued | 18 |
| | 15 |
|
| Customer deposits | 85 |
| | 76 |
|
| Mark-to-market derivative liabilities | 77 |
| | 99 |
|
| Mark-to-market derivative liabilities – affiliates | — |
| | 200 |
|
| Environmental remediation | 37 |
| | 63 |
|
| Current regulatory liabilities | 82 |
| | 76 |
|
| Other current liabilities | 92 |
| | 92 |
|
| Total current liabilities | 797 |
| | 858 |
|
| Long-term Debt, Net | 1,577 |
| | 1,657 |
|
| Deferred Credits and Other Liabilities: | | | |
| Accumulated deferred income taxes, net | 1,025 |
| | 895 |
|
| Accumulated deferred investment tax credits | 5 |
| | 7 |
|
| Regulatory liabilities | 672 |
| | 666 |
|
| Pension and other postretirement benefits | 406 |
| | 495 |
|
| Other deferred credits and liabilities | 399 |
| | 183 |
|
| Total deferred credits and other liabilities | 2,507 |
| | 2,246 |
|
| 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 | 1,965 |
| | 1,965 |
|
| Preferred stock not subject to mandatory redemption | 62 |
| | 62 |
|
| Retained earnings | 360 |
| | 408 |
|
| Accumulated other comprehensive income | 14 |
| | 17 |
|
| Total stockholders’ equity | 2,401 |
| | 2,452 |
|
| TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 7,282 |
| | $ | 7,213 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2013 | | 2012 | | 2011 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 163 |
| | $ | 144 |
| | $ | 196 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 238 |
| | 214 |
| | 206 |
|
| Amortization of debt issuance costs and premium/discounts | 15 |
| | 11 |
| | 8 |
|
| Deferred income taxes and investment tax credits, net | 104 |
| | 104 |
| | 155 |
|
| Other | 4 |
| | (11 | ) | | (14 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | 50 |
| | 23 |
| | 146 |
|
| Materials and supplies | 15 |
| | 20 |
| | (21 | ) |
| Accounts and wages payable | 19 |
| | (21 | ) | | (46 | ) |
| Taxes accrued | 28 |
| | 3 |
| | (12 | ) |
| Assets, other | (53 | ) | | 22 |
| | (3 | ) |
| Liabilities, other | 33 |
| | 72 |
| | (30 | ) |
| Pension and other postretirement benefits | (8 | ) | | (26 | ) | | (101 | ) |
| Counterparty collateral, net | 43 |
| | 40 |
| | 20 |
|
| Premiums paid on long-term debt repurchases | — |
| | (76 | ) | | — |
|
| Net cash provided by operating activities | 651 |
| | 519 |
| | 504 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (701 | ) | | (442 | ) | | (351 | ) |
| Returns from ATXI for construction | — |
| | — |
| | 49 |
|
| Other | 6 |
| | 5 |
| | 6 |
|
| Net cash used in investing activities | (695 | ) | | (437 | ) | | (296 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (110 | ) | | (189 | ) | | (327 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (3 | ) |
| Money pool borrowings, net | 32 |
| | 24 |
| | — |
|
| Redemptions, repurchases, and maturities of long-term debt | (150 | ) | | (333 | ) | | (150 | ) |
| Issuances of long-term debt | 278 |
| | 400 |
| | — |
|
| Capital issuance costs | (2 | ) | | (6 | ) | | — |
|
| Repayments of advances received for construction | (1 | ) | | — |
| | (53 | ) |
| Advances received for construction | 1 |
| | 4 |
| | 5 |
|
| Capital contribution from parent | — |
| | — |
| | 19 |
|
| Net cash provided by (used in) financing activities | 45 |
| | (103 | ) | | (509 | ) |
| Net change in cash and cash equivalents | 1 |
| | (21 | ) | | (301 | ) |
| Cash and cash equivalents at beginning of year | — |
| | 21 |
| | 322 |
|
| Cash and cash equivalents at end of year | $ | 1 |
| | $ | — |
| | $ | 21 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $4, $2, and $2 capitalized, respectively) | $ | 112 |
| | $ | 125 |
| | $ | 137 |
|
| Income taxes, net | (23 | ) | | (22 | ) | | (14 | ) |
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
AMEREN ILLINOIS COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) |
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2012 | | 2011 | | 2010 |
| Cash Flows From Operating Activities: | | | | | |
| Net income | $ | 144 |
| | $ | 196 |
| | $ | 252 |
|
| Income from discontinued operations, net of tax | — |
| | — |
| | (40 | ) |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
| Depreciation and amortization | 214 |
| | 206 |
| | 201 |
|
| Amortization of debt issuance costs and premium/discounts | 11 |
| | 8 |
| | 10 |
|
| Deferred income taxes and investment tax credits, net | 104 |
| | 155 |
| | 210 |
|
| Other | (11 | ) | | (14 | ) | | (3 | ) |
| Changes in assets and liabilities: | | | | | |
| Receivables | 23 |
| | 146 |
| | (84 | ) |
| Materials and supplies | 20 |
| | (21 | ) | | 9 |
|
| Accounts and wages payable | (21 | ) | | (46 | ) | | (44 | ) |
| Taxes accrued | 3 |
| | (12 | ) | | 11 |
|
| Assets, other | 22 |
| | (3 | ) | | 32 |
|
| Liabilities, other | 72 |
| | (30 | ) | | 33 |
|
| Pension and other postretirement benefits | (26 | ) | | (101 | ) | | (7 | ) |
| Counterparty collateral, net | 40 |
| | 20 |
| | (100 | ) |
| Premiums paid on long-term debt repurchases | (76 | ) | | — |
| | — |
|
| Operating cash flows provided by discontinued operations | — |
| | — |
| | 113 |
|
| Net cash provided by operating activities | 519 |
| | 504 |
| | 593 |
|
| Cash Flows From Investing Activities: | | | | | |
| Capital expenditures | (442 | ) | | (351 | ) | | (281 | ) |
| Returns from (advances to) ATXI for construction | — |
| | 49 |
| | (10 | ) |
| Proceeds from note receivable – Genco | — |
| | — |
| | 45 |
|
| Other | 5 |
| | 6 |
| | 5 |
|
| Capital expenditures of discontinued operations | — |
| | — |
| | (6 | ) |
| Net cash used in investing activities | (437 | ) | | (296 | ) | | (247 | ) |
| Cash Flows From Financing Activities: | | | | | |
| Dividends on common stock | (189 | ) | | (327 | ) | | (133 | ) |
| Dividends on preferred stock | (3 | ) | | (3 | ) | | (4 | ) |
| Money pool borrowings, net | 24 |
| | — |
| | — |
|
| Redemptions, repurchases, and maturities: | | | | | |
| Long-term debt | (333 | ) | | (150 | ) | | (40 | ) |
| Preferred stock | — |
| | — |
| | (19 | ) |
| Issuances of long-term debt | 400 |
| | — |
| | — |
|
| Capital issuance costs | (6 | ) | | — |
| | (4 | ) |
| Repayments of generator advances received for construction | — |
| | (53 | ) | | (39 | ) |
| Generator advances received for construction | 4 |
| | 5 |
| | 16 |
|
| Capital contribution from parent | — |
| | 19 |
| | — |
|
| Net financing activities used in discontinued operations | — |
| | — |
| | (107 | ) |
| Net cash used in financing activities | (103 | ) | | (509 | ) | | (330 | ) |
| Net change in cash and cash equivalents | (21 | ) | | (301 | ) | | 16 |
|
| Cash and cash equivalents at beginning of year | 21 |
| | 322 |
| | 306 |
|
| Cash and cash equivalents at end of year | $ | — |
| | $ | 21 |
| | $ | 322 |
|
| | | | | | |
| Cash Paid (Refunded) During the Year: | | | | | |
| Interest (net of $2, $2, and $1 capitalized, respectively) | $ | 125 |
| | $ | 137 |
| | $ | 160 |
|
| Income taxes, net | (22 | ) | | (14 | ) | | (39 | ) |
| Noncash investing activity – asset transfer from ATXI | — |
| | — |
| | 7 |
|
| Noncash financing activity – capital contribution from parent | — |
| | — |
| | 6 |
|
AMEREN ILLINOIS COMPANY (d/b/a AMEREN ILLINOIS) STATEMENT OF STOCKHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2013 | | 2012 | | 2011 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Other Paid-in Capital: | | | | | |
| Beginning of year | 1,965 |
| | 1,965 |
| | 1,952 |
|
| Capital contribution from parent | — |
| | — |
| | 13 |
|
| Other paid-in capital, end of year | 1,965 |
| | 1,965 |
| | 1,965 |
|
| | | | | | |
| Preferred Stock Not Subject to Mandatory Redemption | 62 |
| | 62 |
| | 62 |
|
| | | | | | |
| Retained Earnings: | | | | | |
| Beginning of year | 360 |
| | 408 |
| | 542 |
|
| Net income | 163 |
| | 144 |
| | 196 |
|
| Common stock dividends | (110 | ) | | (189 | ) | | (327 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (3 | ) |
| Retained earnings, end of year | 410 |
| | 360 |
| | 408 |
|
| | | | | | |
| Accumulated Other Comprehensive Income: | | | | | |
| Deferred retirement benefit costs, beginning of year | 14 |
| | 17 |
| | 20 |
|
| Change in deferred retirement benefit costs | (3 | ) | | (3 | ) | | (3 | ) |
| Deferred retirement benefit costs, end of year | 11 |
| | 14 |
| | 17 |
|
| Total accumulated other comprehensive income, end of year | 11 |
| | 14 |
| | 17 |
|
| | | | | | |
| Total Stockholders’ Equity | $ | 2,448 |
| | $ | 2,401 |
| | $ | 2,452 |
|
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
AMEREN ILLINOIS COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (In millions) |
| | | | | | | | | | | |
| | December 31, |
| | 2012 | | 2011 | | 2010 |
| Common Stock | $ | — |
| | $ | — |
| | $ | — |
|
| Other Paid-in Capital: | | | | | |
| Beginning of year | 1,965 |
| | 1,952 |
| | 2,223 |
|
| Capital contribution from parent | — |
| | 13 |
| | 6 |
|
| 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 | 1,965 |
| | 1,965 |
| | 1,952 |
|
| Preferred Stock Not Subject to Mandatory Redemption: | | | | | |
| Beginning balance | 62 |
| | 62 |
| | 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 |
| | 62 |
| | 62 |
|
| Retained Earnings: | | | | | |
| Beginning of year | 408 |
| | 542 |
| | 709 |
|
| Net income | 144 |
| | 196 |
| | 252 |
|
| Common stock dividends | (189 | ) | | (327 | ) | | (133 | ) |
| Preferred stock dividends | (3 | ) | | (3 | ) | | (4 | ) |
| Transfer of AERG to parent (Notes 1 and 16) | — |
| | — |
| | (281 | ) |
| Other | — |
| | — |
| | (1 | ) |
| Retained earnings, end of year | 360 |
| | 408 |
| | 542 |
|
| Accumulated Other Comprehensive Income: | | | | | |
| Deferred retirement benefit costs, beginning of year | 17 |
| | 20 |
| | 25 |
|
| Change in deferred retirement benefit costs | (3 | ) | | (3 | ) | | (4 | ) |
| Change in accumulated other comprehensive income from discontinued operations | — |
| | — |
| | (1 | ) |
| Deferred retirement benefit costs, end of year | 14 |
| | 17 |
| | 20 |
|
| Total accumulated other comprehensive income, end of year | 14 |
| | 17 |
| | 20 |
|
| Total Stockholders’ Equity | $ | 2,401 |
| | $ | 2,452 |
| | $ | 2,576 |
|
The accompanying notes as they relate to Ameren Illinois are an integral part of these consolidated financial statements.
AMEREN CORPORATION (Consolidated)
UNION ELECTRIC COMPANY (d/b/a Ameren Missouri)
AMEREN ILLINOIS COMPANY (Consolidated)(d/b/a Ameren Illinois)
COMBINED NOTES TO FINANCIAL STATEMENTS December 31, 20122013
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 its equity interests in 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. 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.
Union Electric Company, ordoing 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. Ameren Missouri 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. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.
Ameren Illinois Company, ordoing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois was created by the merger of CILCO and IP with and into CIPS.CIPS in 2010. CIPS was incorporated in Illinois in 1923 and is the successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to portions of central and southern Illinois having an estimated population of 3.1 million in an area of 40,000 square miles. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 806,000767,000 customers.
AER consists of non-rate-regulated operations, including Genco, AERG, Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business and is developing the Illinois Rivers project.
InOn March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. On December 2012,2, 2013, Ameren completed the divestiture of New AER to IPH. On January 31, 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. See Note 16 – Divestiture Transactions and Discontinued Operations for additional information.
As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that it intends to,
New AER and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren’s analysis of the current and projected future financial condition of its Merchant Generation business segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this business segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately to eliminate, the Merchant Generation business segment’s, including Genco's, reliance on Ameren’s financial support and shared services support. Furthermore, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying values of the Merchant Generationgas-fired energy centers exceptqualified for the Joppa coal-fired energy center, to their estimated fair values. See Note 17 - Impairment and Other Charges for additional information. Ameren's date and method of exit from the Merchant Generation business is currently uncertain. Exit strategies may include the sale of all or parts of the Merchant Generation business and the restructuring of all or a portion of Ameren's equity position in Genco. Ameren's Merchant Generation long-lived assets have not been classified as held-for-sale under authoritative accounting guidance as all criteria to qualify for thatdiscontinued operations presentation were not metbeginning March 14, 2013. In addition, as of December 31, 2012. Specifically,2, 2013, Ameren did not consider it probable that a disposition would occur within one year.
On October 1, 2010, Ameren, CIPS, CILCO, IP, AERGabandoned the Meredosia and AER completed a two-step corporate internal reorganization. The first stepHutsonville energy centers upon the completion of the reorganizationdivestiture of New AER to IPH. Ameren is prohibited from operating these energy centers through December 31, 2020, as a provision of the Illinois Pollution Control Board's November 2013 order granting IPH a variance of the MPS. As a result, Ameren determined that the Meredosia and Hutsonville energy centers qualified for discontinued operations presentation as of December 2, 2013. The Meredosia and Hutsonville energy centers ceased operations at December 31, 2011, and therefore 2011 was the last year those energy centers had a material effect on Ameren's consolidated financial statements. As a result of these events, Ameren Illinois Merger. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Amerenhas segregated New AER’s and the subsequent contribution by Ameren of the AERG stock to AER. Ameren Illinois segregated AERG’sElgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers’ operating results, assets, and cash flowsliabilities and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. Unless otherwise stated, these notes to the financial statements exclude discontinued operations for all periods presented. See Note 16 - 2010 Corporate Reorganization– Divestiture Transactions and Discontinued Operations for additional information.information regarding that presentation.
The financial statements of Ameren and Ameren Illinois are prepared on a consolidated basis, and therefore include the accounts of their respectiveits majority-owned subsidiaries. Ameren Illinois' financial statements are consolidated becauseMissouri and Ameren Illinois included AERG in its statements of income and cash flows during 2010. Ameren Missouri hashave no subsidiaries and therefore itstheir financial statements are not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of
financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, Ameren Missouri and Ameren Illinois defer certain costs as assets pursuant to actions of rate regulators or because of expectations that the companies will be able to recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts as liabilities pursuant to actions of rate regulators or based on 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. In addition to the cost recovery mechanisms discussed in the Purchased Gas, Power and Fuel Rate-adjustment Mechanisms section below, Ameren Missouri and Ameren Illinois have approvals from regulators to use other cost recovery mechanisms. Ameren Missouri has a vegetation management and infrastructure inspection cost tracker, a pension and postretirement benefit cost tracker, an uncertain tax positions tracker, a renewable energy standards cost tracker, and, starting in 2013, a storm restoration cost tracker, and the MEEIA energy efficiency cost recovery mechanisms.rider. In addition to participating in the IEIMA's formula rate regulatory framework, Ameren
Illinois has an environmental cost rider, an asbestos-related litigation rider, an energy efficiency rider, and a bad debt rider. See Note 2 -– Rate and Regulatory Matters for additional information on regulatory assets and liabilities. In addition, other costs that Ameren Missouri and Ameren Illinois expect to recover from customers are 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 loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has a rate mechanism that adjusts rates for bad debt expensenet write-offs of customer accounts receivable 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, 20122013, and 20112012:
| | | | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2013 | | | | | | | |
Fuel(b)(a) | | | $ | 144 |
| | $ | — |
| | $ | 144 |
|
| Gas stored underground | | | 17 |
| | 110 |
| | 127 |
|
| Other materials and supplies | | | 191 |
| | 64 |
| | 255 |
|
| | Ameren(a) | | Ameren Missouri | | Ameren Illinois | | $ | 352 |
| | $ | 174 |
| | $ | 526 |
|
| 2012 | | | | | | | | | | | |
Fuel(b)(a) | $ | 276 |
| | $ | 198 |
| | $ | — |
| | $ | 198 |
| | $ | — |
| | $ | 198 |
|
| Gas stored underground | 131 |
| | 18 |
| | 113 |
| | 18 |
| | 113 |
| | 131 |
|
| Other materials and supplies | 297 |
| | 181 |
| | 60 |
| | 181 |
| | 60 |
| | 241 |
|
| $ | 704 |
| | $ | 397 |
| | $ | 173 |
| | $ | 397 |
| | $ | 173 |
| | $ | 570 |
|
| 2011 | | | | | | |
Fuel(b)(a) | $ | 251 |
| | $ | 150 |
| | $ | — |
| |
| Gas stored underground | 171 |
| | 22 |
| | 149 |
| |
| Other materials and supplies | 290 |
| | 176 |
| | 50 |
| |
| $ | 712 |
| | $ | 348 |
| | $ | 199 |
| |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(b) | Consists of coal, oil, paint, propane, and tire chips.propane. |
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 incurred 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 2013, 2012 2011 and 20102011 ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, weWe 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 isin accordance with the utility industry's 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 during 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 20122013, 20112012 and 20102011:
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Ameren | 8% - 9% |
| | 8% - 9% |
| | 8% - 9% |
| |
| Ameren Missouri | 8 | % | | 8 | % | | 8 | % | 8 | % | | 8 | % | | 8 | % |
| Ameren Illinois | 9 | % | | 9 | % | | 9 | % | 8 | % | | 9 | % | | 9 | % |
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. AsAmeren and Ameren Illinois had recorded goodwill of $411 million at December 31, 2012, Ameren’s2013, and Ameren Illinois’ goodwill related to Ameren’s acquisitions of IP in 2004 and of CILCORP in 2003.2012.
Ameren has threetwo reporting units, which also represent Ameren’s reportable segments. Ameren's reporting units are Ameren Missouri and Ameren Illinois, and Merchant Generation.Illinois. Ameren Illinois has one reporting unit, Ameren Illinois. Ameren’s and Ameren Illinois' reporting units have been defined and goodwill has been evaluated at the operating segment level in accordance with authoritative accounting guidance. Our reporting units represent businesses for which discrete financial information is available and reviewed regularly by management. All of Ameren's and Ameren Illinois' goodwill at December 31, 2012,2013, and 20112012, has been assigned to the Ameren Illinois reporting unit. See Note 17 - Impairment and Other Charges for information regarding the 2010 goodwill impairment charge, which represented all the goodwill assigned to Ameren's Merchant Generation reporting unit.
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. Ameren and Ameren Illinois applied a qualitative goodwill evaluation model for itstheir annual goodwill impairment test conducted as of October 31, 2012.2013. Based on the results of Ameren’s and Ameren Illinois’ qualitative assessment, Ameren and Ameren Illinois believe it
was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value as of October 31, 2012,2013, indicating no impairment of Ameren’s or Ameren Illinois’ goodwill. The following factors, not meant to be all-inclusive,among others, were considered by Ameren and Ameren Illinois when assessing whether it was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value for the October 31, 2012,2013, test:
Macroeconomicmacroeconomic conditions, including those conditions within Ameren Illinois’ service territory;
Pendingpending rate case outcomes and projections of future rate case outcomes;
Changeschanges in laws and potential law changes;
Observableobservable industry market multiples;
Achievementachievement of IEIMA performance metrics and the yield of the 30-year United States treasury bonds; and
Actualactual and forecasted financial performance.
The goodwill assigned to the Ameren Illinois reporting unit on the December 31, 20122013, balance sheets of Ameren and Ameren Illinois had no accumulated goodwill impairment losses. Ameren and Ameren Illinois will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, and observable industry market multiples of the Ameren Illinois reporting unit for signs of possible declines in estimated fair value and potential goodwill impairment.
Intangible Assets. Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At December 31, 2012,2013, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $1622 million and $1422 million at December 31, 2012,2013, respectively. The book value of Ameren's and Ameren Missouri's renewable energy credits was $714 million and $714 million at December 31, 2011,2012, respectively.
Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. In accordance with the MoPSC's 2012 electric rate order, most of Ameren Missouri's amortization of intangible assets is deferred as a regulatory asset pending future recovery from customers through rates. The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri, and Ameren Illinois during the years ended December 31, 2013, 2012 2011,, and 2010. Amortization expense based on Ameren Missouri's renewable energy standards compliance costs is expensed up to $1 million2011 annually beginning in August each year in accordance with MoPSC's 2011 electric rate order, and the remainder is deferred as a regulatory asset pending recovery from customers through rates. The following table does not include the intangible asset impairment charges referenced below..
| | | | 2012 | | 2011 | | 2010 | | 2013 | | 2012 | | 2011 |
| Ameren Missouri | $ (a) |
| | $ (a) |
| | $ | 6 |
| $ | (a) |
| $ | (a) |
| $ | (a) |
|
| Ameren Illinois | 4 |
| | 3 |
| | 7 |
| | 13 |
| | 4 |
| | 3 |
|
Other(b)(c) | 3 |
| | 3 |
| | 22 |
| |
Ameren(c) | $ | 7 |
| | $ | 6 |
| | $ | 35 |
| |
| Ameren | | $ | 13 |
| $ | 4 |
| $ | 3 |
|
| |
(b) | Consists of renewable energy credit expense for Marketing Company and emission allowance expense for Genco and AERG. |
| |
(c) | Includes allowances consumed that were recorded through purchase accounting. |
During 2011, Ameren recorded a $2 million noncash pretax impairment charge of Merchant Generation's emission allowances. Ameren Missouri recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowances, which had no impact on earnings. The impairment was triggered by a significant observable decline in the market price of SO2 and NOX allowances used for CAIR compliance. See Note 17 - Impairment and Other Charges for additional information, including a discussion of the 2010 intangible asset impairment charge.
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 amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. See Note 17 - Impairment and Other Charges for additional information about Ameren’s
During 2011, the MoPSC issued an electric rate order that disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of the amount recovered from property insurance. Consequently, Ameren and Ameren Missouri's long-lived asset impairments.Missouri each recorded a pretax charge to earnings of $89 million, which is reflected as "Taum Sauk regulatory disallowance" on each company's statement of income.
Investments
Ameren and Ameren Missouri evaluate for impairment the investments held in Ameren Missouri’s nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which Ameren Missouri believes would be recovered in electric rates paid by its customers. Accordingly, Ameren and Ameren Missouri 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
The Ameren Companies 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.
Beginning in 2012, Ameren Illinois elected to participate in the performance-based formula ratemaking framework pursuant to the IEIMA. The IEIMA provides for an annual reconciliation of Ameren Illinois' electric distribution revenue requirement. As of each balance sheet date, Ameren Illinois records its best estimate of the electric distribution revenue impact resulting from the reconciliation of the revenue requirement necessary to reflect the actual costs incurred for that year with the revenue requirement that was in effect for billing purposes for that year. If the current year's revenue requirement is greater than the revenue
requirement customer rates were based upon, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional costs from customers within the next two years. If the current year's revenue requirement is less than the revenue requirement customer rates were based upon, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within the next two years. See Note 2 -– Rate and Regulatory Matters for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.
Beginning in 2013,Similar to the IEIMA process described above, Ameren Illinois willand ATXI record the impact of a revenue requirement reconciliation for itseach company's electric transmission jurisdiction, pursuant to FERC-approved rate treatment.
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 “Operating Revenues - Other.”
Nuclear Fuel
Ameren Missouri’s cost of nuclear fuel is capitalized and then amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated and sold, and thatsold. That cost is charged to "Operating Expenses -– Fuel" in the statement of income.
Purchased Gas, Power and Fuel Rate-adjustment Mechanisms
Ameren Missouri and Ameren Illinois 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, 20122013, and 20112012, related to the rate-adjustment mechanisms discussed below.
In Ameren Missouri’s and Ameren Illinois’ retail natural gas utility jurisdictions, changes in natural gas costs are reflected in billings to their natural gas utility customers through PGA clauses. The differences 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 Ameren Illinois’ retail electric utility jurisdictions, changes in purchased power costs and transmission service costcosts are reflected in billings to their electric utility customers through pass-through rate-adjustment clauses. The differences between actual purchased power and transmission service 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.
Ameren Missouri has a FAC that allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel, certain fuel additives, emission allowances, purchased power costs, transmission costs and revenues, and MISO costs and revenues, net of off-system sales revenues, greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudency
review. The differences between the cost of fuel incurred and the cost of fuel recovered from Ameren Missouri customers' base rates are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to Ameren Missouri’s electric utility customers in a subsequent period. The MoPSC's December 2012 electric rate order changed the FAC to include activated carbon, limestone and urea costs, along with transmission revenues starting in 2013.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren, Ameren Missouri and Ameren Illinois using settlement information provided by MISO. TheseAmeren Missouri records these purchase and sale transactions are accounted for on a net hourly position. We recordAmeren Missouri records net purchases in a single hour in “Operating Expenses - Purchased power” and net sales in a single hour in “Operating Revenues - Electric” in our statementsits statement of income. Ameren Illinois records net purchases in “Operating Expenses - Purchased Power” in its statement of income (loss).to reflect all of its MISO transactions relating to the procurement of power for its customers. On occasion, Ameren Missouri and Ameren Illinois 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, the Ameren CompaniesMissouri and Ameren Illinois recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated, and the Ameren Companies recognize revenues once the resettlement amount is received.
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 levied on us are reflected on Ameren Missouri electric customer electric bills and on Ameren Missouri and Ameren Illinois customer natural gas customer bills. They are recorded gross in “Operating Revenues -– Electric,” “Operating Revenues -– Gas” and “Operating Expenses -– Taxes other than income taxes” on the statement of income (loss). Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the customer 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 -– Electric,” “Operating Revenues - Gas”– Gas,” and “Operating Expenses -– Taxes other than income taxes” for the years ended 20122013, 20112012 and 20102011:
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
| Ameren Missouri | $ | 152 |
| | $ | 139 |
| | $ | 137 |
|
| Ameren Illinois | 61 |
| | 54 |
| | 57 |
|
| Ameren | $ | 213 |
| | $ | 193 |
| | $ | 194 |
|
|
| | | | | | | | | | | |
| | 2012 | | 2011 | | 2010 |
| Ameren Missouri | $ | 139 |
| | $ | 137 |
| | $ | 130 |
|
| Ameren Illinois | 54 |
| | 57 |
| | 59 |
|
| Ameren | $ | 193 |
| | $ | 194 |
| | $ | 189 |
|
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 based on statutory tax rates.
We recognize that regulators will probably reduce future revenues for deferred tax liabilities that were 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, have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery in rates of future income taxes, resulting principally from the reversal of the equity portion of the allowance for funds used during construction. This refers to equity and temporary differences related to property and plant acquired before 1976construction that werewas an unrecognized temporary differencesdifference prior to the adoption of the authoritative accounting guidance for income taxes.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; thein accordance with GAAP. 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.
For certain renewable energy construction projects placed in service, in 2010 and 2012, Ameren Missouri elected to seek federal cash tax grants in lieu of the investment tax credits for which the projects also qualified. These grants were accounted for using a grant recognition accounting model. Ameren Missouri elected to reduce the basis of property as cash grants arewere received, which will reduce the amount of depreciation expense recognized in future periods. In 2012, Ameren Missouri received $18 million in federal cash tax grants.
Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be 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
As of December 31, 2013, Ameren’s noncontrolling interests comprised the 20% of EEI not owned by Ameren andincluded the preferred stock not subject to mandatory redemption of Ameren’s subsidiaries. TheseAmeren Missouri and Ameren Illinois. As of December 31, 2012, Ameren's noncontrolling interests also included the 20% of EEI not owned by Ameren. All noncontrolling interests are classified as a component of equity separate from Ameren’s
equity in its consolidated balance sheet.
Earnings per Share
ThereBasic earnings per share is computed by dividing net income attributable to Ameren Corporation by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to Ameren Corporation by the diluted weighted-average number of common shares outstanding during the period. Diluted earnings per share reflects the potential dilution that would occur if certain stock-based performance share units were no material differences betweensettled.
The following table presents Ameren’s basic and diluted earnings per share amounts incalculations and reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the years ended December 31, 2013, 2012, and 2011:
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
| Net income (loss) attributable to Ameren Corporation: | | | | | |
| Continuing operations | $ | 512 |
| | $ | 516 |
| | $ | 431 |
|
| Discontinued operations | (223 | ) | | (1,490 | ) | | 88 |
|
| Net income (loss) attributable to Ameren Corporation | $ | 289 |
| | $ | (974 | ) | | $ | 519 |
|
| | | | | | |
| Average common shares outstanding – basic | 242.6 |
| | 242.6 |
| | 241.5 |
|
| Assumed settlement of performance share units | 1.9 |
| | 0.4 |
| | 0.6 |
|
| Average common shares outstanding – diluted | 244.5 |
| | 243.0 |
| | 242.1 |
|
| | | | | | |
| Earnings (loss) per common share – basic: | | | | | |
| Continuing operations | $ | 2.11 |
| | $ | 2.13 |
| | $ | 1.79 |
|
| Discontinued operations | (0.92 | ) | | (6.14 | ) | | 0.36 |
|
| Earnings (loss) per common share – basic | $ | 1.19 |
| | $ | (4.01 | ) | | $ | 2.15 |
|
| | | | | | |
| Earnings (loss) per common share – diluted: | | | | | |
| Continuing operations | $ | 2.10 |
| | $ | 2.13 |
| | $ | 1.79 |
|
| Discontinued operations | (0.92 | ) | | (6.14 | ) | | 0.36 |
|
| Earnings (loss) per common share – diluted | $ | 1.18 |
| | $ | (4.01 | ) | | $ | 2.15 |
|
| | | | | | |
Average performance share units excluded from calculation(a) | 0.1 |
| | 0.7 |
| | — |
|
| |
| (a) | Weighted-average number of performance share units that were excluded from the “Assumed settlement of performance share units” provided above because the performance or market conditions related to the awards had not yet been met. |
Supplemental Cash Flow Information
The following table presents additional information regarding Ameren's consolidated statement of cash flows for the years ended December 31, 2013,2012 and 20102011. The number of dilutive stock options, restricted stock shares,:
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
| Cash paid (refunded) during the year: |
| | | | | |
| Interest | | | | | |
Continuing operations(a) | $ | 362 |
| | $ | 384 |
| | $ | 393 |
|
Discontinued operations(b) | 31 |
| | 49 |
| | 60 |
|
| | $ | 393 |
| | $ | 433 |
| | $ | 453 |
|
| | | | | | |
| Income taxes, net | | | | | |
| Continuing Operations | $ | 116 |
| | $ | 10 |
| | $ | (47 | ) |
| Discontinued Operations | (108 | ) | | (9 | ) | | (14 | ) |
| | $ | 8 |
| | $ | 1 |
| | $ | (61 | ) |
| |
| (a) | Net of $20 million, $17 million, and $27 million capitalized, respectively. |
| |
| (b) | Net of $17 million, $13 million, and $3 million capitalized, respectively. |
See Note 3 – Property and performance share units had an immaterial impactPlant, Net, for information on earnings per share. There were no assumed stock option conversions in 2010, as the remaining stock options were not dilutive. All of Ameren’s stock options expired in February 2010.accrued capital expenditures.
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 impactaffect the Ameren Companies.
Disclosures about Fair Value Measurements
In May 2011, FASB issued additional authoritative guidance regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect the Ameren Companies' results of operations, financial position, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of
2012. See Note 8 Fair Value Measurements for the required additional disclosures.
Presentation of Comprehensive Income
In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies' Companies’
results of operations, financial position, or liquidity.
In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. The amendments will not affect the Ameren Companies' results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance will bewas effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The amounts reclassified out of accumulated OCI for the Ameren Companies corresponding to continuing operations related to pension and other postretirement plan activity. These amounts were immaterial for the year ended December 31, 2013, on a prospective basis.and therefore no additional disclosures were required.
Disclosures about Offsetting Assets and Liabilities
In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments willAmeren Companies adopted this guidance for the first quarter of 2013. The implementation of this additional guidance did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. See Note 7 – Derivative Financial Instruments for the required additional disclosures.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a
tax credit carryforward is available under the tax law. Currently, any unrecognized tax benefit is recorded in “Other deferred credits and liabilities” on Ameren's, Ameren Missouri's, and Ameren Illinois' balance sheets. After this guidance becomes effective, any unrecognized tax benefit will be recorded in “Accumulated deferred income taxes, net” as a reduction to the deferred tax assets for net operating loss, a similar tax loss, and tax credit carryforwards on the respective balance sheets. At December 31, 2013, unrecognized tax benefits of $48 million and $15 million would have been recorded in “Accumulated deferred income taxes, net” at Ameren and Ameren Missouri, respectively under this new guidance. To the extent that an unrecognized tax benefit exceeds these carryforwards, the excess would continue to be recorded in “Other deferred credits and liabilities” on the respective balance sheets, consistent with current authoritative accounting guidance. The amended guidance will not affect the Ameren Companies' results of operations or liquidity, as this guidance is presentation-related only. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2013 with retrospective application required.2014.
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 and Ameren Missouri Genco and AERG have recorded AROs for retirement costs associated with Ameren Missouri’s Callaway energy center decommissioning costs, asbestos removal, CCR storage facilities, and river structures. Also, Ameren and Ameren Illinois hashave recorded AROs for retirement costs associated with asbestos removal. In addition, Ameren, Ameren
Missouri and Ameren Illinois 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 2012ended December 31, 2013, and 2011:2012:
| | | | Ameren Missouri(a) | | Ameren Illinois(b) | | Genco | | AERG | | Ameren(a) | | Ameren Missouri(a) | | Ameren Illinois(b) | | Ameren(a) | |
| Balance at December 31, 2010 | $ | 363 |
| | $ | 3 |
| | $ | 74 |
| | $ | 35 |
| | $ | 475 |
| | |
| Liabilities incurred | — |
| | — |
| | (c) |
| | — |
| | (c) |
| | |
| Liabilities settled | (1 | ) | | (c) |
| | (2 | ) | | (c) |
| | (3 | ) | | |
Accretion in 2011(d) | 20 |
| | (c) |
| | 5 |
| | 2 |
| | 27 |
| | |
Change in estimates(e) | (54 | ) | | (c) |
| | (6 | ) | | (6 | ) | | (66 | ) | | |
| Balance at December 31, 2011 | $ | 328 |
| | $ | 3 |
| | $ | 71 |
| | $ | 31 |
| | $ | 433 |
| (f) | $ | 328 |
| | $ | 3 |
| | $ | 331 |
| |
| Liabilities incurred | — |
| | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| |
| Liabilities settled | (1 | ) | | (c) |
| | (5 | ) | | (c) |
| | (6 | ) | | (1 | ) | | (c) |
| | (1 | ) | |
Accretion in 2012(d) | 18 |
| | (c) |
| | 4 |
| | 2 |
| | 24 |
| | 18 |
| | (c) |
| | 18 |
| |
Change in estimates(e) | | 1 |
| | (c) |
| | 1 |
| |
| Balance at December 31, 2012 | | $ | 346 |
| | $ | 3 |
| | $ | 349 |
| |
| Liabilities incurred | | — |
| | — |
| | — |
| |
| Liabilities settled | | (1 | ) | | (c) |
| | (1 | ) | |
Accretion in 2013(d) | | 19 |
| | (c) |
| | 19 |
| |
Change in estimates(g)(e) | 1 |
| | (c) |
| | (3 | ) | | 2 |
| | (c) |
| | 2 |
| | (c) |
| | 2 |
| |
| Balance at December 31, 2012 | $ | 346 |
| | $ | 3 |
| | $ | 69 |
| | $ | 35 |
| | $ | 453 |
| (h) | |
| Balance at December 31, 2013 | | $ | 366 |
| | $ | 3 |
| | $ | 369 |
| |
| |
| (a) | The nuclear decommissioning trust fund assets of $408494 million and $357408 million as of December 31, 20122013, and 20112012, respectively, wereare restricted for decommissioning of the Callaway energy center. |
| |
| (b) | Balance included in “Other deferred credits and liabilities” on the balance sheet. |
| |
| (d) | Accretion expense was recorded as an increase to regulatory assets at Ameren Missouri and Ameren Illinois. |
| |
| (e) | Ameren Missouri changed its fair value estimate related to its Callaway energy center decommissioning costs because of a cost study performed in 2011 and a decline in the cost escalation factor assumptions. Additionally, Ameren Missouri, Genco and AERG changed their fair value estimates related to retirement costs for asbestos removal, river structures and their CCR storage facilities. |
| |
(f) | Balance included $5 million in "Other current liabilities" on the balance sheet as of December 31, 2011.
|
| |
(g) | Ameren Missouri and Genco changed their fair value estimates for asbestos removal. The estimates for asbestos removal costs at Genco's Hutsonvillein 2012 and Meredosia energy centers decreased because less asbestos than anticipated was found in the energy centers' structures during reviews made after the closure of these energy centers,2013, and because removal was more cost efficient than anticipated due to the closure. Additionally, Genco and AERG changed their fair value estimates related to updated retirement dates for certain CCR storage facilities.facilities in 2013. |
| |
(h) | Balance included $8 million in "Other current liabilities" on the balance sheet as of December 31, 2012.See Note 16 – Divestiture Transactions and Discontinued Operations for additional information on the AROs related to the abandoned Meredosia and Hutsonville energy centers, which are presented as discontinued operations and therefore not included in the table above.
|
Employee Separation Charges
During the fourth quarter of 2011, as part of efforts to reduce operations and maintenance expenses, Ameren Missouri and Ameren Services extended voluntary separation offers consistent with Ameren’s standard management separation program to eligible management and labor union-represented employees. Approximately 340 employees of Ameren Missouri and Ameren Services accepted the offers and left their employment by December 31, 2011. Ameren and Ameren Missouri recorded a pretax charge to earnings of $28 million and $27 million, respectively, for the severance costs related to these offers. These charges were recorded in “Other operations and maintenance" expense in each company’s statement of income for the year ended December 31, 2011. Substantially all of the severance costs were paid in the first quarter of 2012 and were recorded in “Accounts and wages payable” on each company’s balance sheet at December 31, 2011.2012. The severance costs related to participating Ameren Services employees were allocated to affiliates consistent with the terms of its support services agreement, which is described in Note 14 -– Related Party Transactions.
In each of the past three years, Ameren's Merchant
Generation segment initiated separation programs to reduce positions under the terms and benefits consistent with Ameren's standard management separation program. Ameren recorded pretax charges related to these programs of $1 million, $4 million, and $4 million in 2012, 2011, and 2010, respectively. The 2012 and 2010 charges were recorded in "Other operations and maintenance" expense on Ameren's consolidated statement of income. The 2011 charge related to the closure of the Meredosia and Hutsonville energy centers and was recorded in "Impairment and other charges" on Ameren's consolidated statement of income. See Note 17 - Impairment and Other Charges for additional information.
Merchant Generation Asset Sales
In February 2012, Ameren completed the sale of its Medina Valley energy center's net property and plant for cash proceeds of $16 million and an additional $1 million to be paid at the two-year anniversary date of the sale if all terms of the sale agreement have been met. Ameren recognized a $10 million pretax gain from this sale. In October 2012, the buyer of the Medina Valley energy center asserted that AER has not met all the terms of the sale agreement. AER is evaluating the buyer's claim. The dollar amount of the asserted claim does not
materially differ from the payment due at the two-year anniversary date of the sale.
In 2012, Ameren completed the sale of some Merchant Generation land and an office building for cash proceeds of $5 million. Ameren recognized a $1 million pretax gain from these sales.
In June 2010, Ameren completed the sale of 25% of Genco's Columbia CT energy center to the city of Columbia, Missouri. Ameren received cash proceeds of $18 million and recognized a $5 million pretax gain from the sale. In June 2011, Ameren completed the sale of Genco's remaining interest in the Columbia CT energy center to the city of Columbia, Missouri. Ameren received cash proceeds of $45 million and recognized an $8 million pretax gain from the sale. In 2011, Ameren sold additional property and assets for cash proceeds of $4 million, which resulted in pretax gains of $4 million.
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, 2010, and 2011 Electric Rate Orders
Noranda, Ameren Missouri's largest electric customer, and the MoOPC appealed certain aspects of the MoPSC's January 2009 electric rate order to the Stoddard County Circuit Court. In September 2009, the Stoddard County Circuit Court issued a stay of the electric order as it applied specifically to Noranda's electric service account, which allowed Noranda to pay a portion of its monthly billings into the Stoddard County Circuit Court's registry until the court ultimately rendered a decision on the appeal. In August 2010, the Stoddard County Circuit Court issued a judgment that reversed part of the MoPSC's January 2009 electric rate order. However, upon issuance, the Stoddard County Circuit Court suspended its own judgment. Ameren Missouri appealed the Stoddard County Circuit Court's judgment and, in November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC's January 2009 electric rate order. In March 2012, the Stoddard County Circuit Court released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21 million, reducing the previously recorded trade accounts receivable.
In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $230 million. The MIEC, MoOPC, and four industrial customers appealed certain aspects of the MoPSC's May 2010 electric rate order to the Cole County Circuit Court. In December 2010, the Cole County Circuit Court issued a stay of the electric order as it applied specifically to four industrialcustomers' electric service accounts, which allowed them to pay a portion of their
monthly billings into the Cole County Circuit Court's registry until thecourt ultimately rendered a decision on the appeal. In May 2012, the Cole County Circuit Court issued a ruling that upheld the MoPSC's May 2010 electric rate order and released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $16 million, reducing the previously recorded trade accounts receivable.
In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million, including $52 million related to an 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. The MoPSC's July 2011 electric rate order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result, Ameren and Ameren Missouri each recorded in 2011 a pretax charge to earnings of $89 million. Ameren recorded the charge to “Impairment and other charges” and Ameren Missouri recorded the charge to “Loss from regulatory disallowance.” See Note 17 - Impairment and Other Charges for additional information. In July 2012, the Missouri Court of Appeals upheld the MoPSC's July 2011 electric rate order. Ameren Missouri did not seek further appeal of the MoPSC order.
2012 Electric Rate Order
In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million, including $84 million related to an anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its July 2011 electric rate order. The annual increase request also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other nonfuel costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The revenue increase was based on a 9.8% return on equity, a capital structure composed of 52.3% common equity, and a rate base of $6.8 billion.
The MoPSC approved Ameren Missouri's continued use of its FAC, with no change to its 95% sharing percentage, but with a modification relating to transmission revenues. Transmission revenues previously included in base rates will be included in the FAC prospectively. This change resulted in the portion of the rate increase attributed to net fuel costs being reduced, and the portion attributed to other nonfuel costs being increased, by $33 million as compared to base rates authorized in the MoPSC's July 2011 electric rate order. This change in regulatory treatment will have no immediate impact on earnings. Transmission charges that had previously been included in the FAC remain in the FAC. Further, the order clarified that changes in costs for activated carbon, limestone and urea are included in the FAC.
The MoPSC order approved the continued use of Ameren Missouri's vegetation management and infrastructure inspection cost tracker, pension and postretirement benefit cost tracker, renewable energy standards cost tracker, and the uncertain tax positions tracker.
The order also established a storm restoration cost tracking mechanism to facilitate the recovery in future rate cases of storm costs that vary from those included in rates and allowed retention of the refund received in June 2012 from Entergy related to a power purchase agreement that existed prior to the implementation of the FAC. See below under Federal for additional information about this refund, which remains subject to appeal, and Ameren Missouri's power purchase agreement with Entergy. However, the MoPSC did not approve Ameren Missouri's request for plant-in-service accounting treatment for assets placed in service between rate cases or recovery of its 2011 severance costs.
Rate changes consistent with the order became effective on January 2, 2013. In January 2013, Ameren Missouri appealed the amount of property taxes included in the 2012 electric rate order to the Missouri Court of Appeals, Western District. In February 2013, the MoOPC, the MIEC and others filed separate appeals to the Missouri Court of Appeals, Western District, relating to the 2012 electric rate order's treatment of transmission costs in the FAC and other items. A decision is expected by the Missouri Court of Appeals, Western District, in 2013. Ameren Missouri cannot predict the ultimate outcome of its appeal.
MEEIA Order
The MEEIA established a regulatory framework that, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. The law requires the MoPSC to ensure that a utility's financial incentives are aligned to help customers use energy more efficiently, to provide timely cost recovery, and to provide earnings opportunities associated with cost-effective energy efficiency programs. Missouri does not have a law mandating energy efficiency standards.
The MoPSC's December 2012 electric rate order approved Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs, and associated cost recovery mechanisms and incentive awards. Beginning in 2013, Ameren Missouri will invest approximately $147 million over the next three years for energy efficiency programs. The order allows for Ameren Missouri to collect its program costs and 90% of its projected lost revenue from customers over the same three years starting on January 2, 2013. The remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings.
Additionally, the order provides for an incentive award that would allow Ameren Missouri to earn additional revenues based on achievement of certain energy efficiency goals, including approximately $19 million if 100% of its energy efficiency goals are achieved during the three-year period, with the potential to
earn more if Ameren Missouri's energy savings exceed those goals. Ameren Missouri must achieve at least 70% of its energy efficiency goals before it earns any incentive award. The recovery of the incentive award from customers, if the energy efficiency goals are achieved, would begin after the three-year energy efficiency plan is complete and upon the effective date of an electric service rate order or potentially with the future adoption of a rider mechanism.
FAC Prudence Review
Missouri law requires the MoPSC to perform prudence reviews of Ameren Missouri's FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that
Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18$18 million,, including $1$1 million for interest, in 2011 for its obligation to refund to Ameren Missouri'sits electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009.
Ameren Missouri disagrees with the MoPSC order's classification of these sales and believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. In May 2012, upon appeal by Ameren Missouri, the Cole County Circuit Court reversed the MoPSC's April 2011 order. In June 2012, the MoPSC and a group of large industrial customers filed an appeal of the Cole County Circuit Court's ruling to the Missouri Court of Appeals, Western District. Ameren Missouri has not recorded additional revenues as a result of the Cole County Circuit Court'sIn May 2012 ruling, as the MoPSC's appeal to2013, the Missouri Court of Appeals is ongoing. A decision is expectedupheld the MoPSC’s April 2011 order and reversed the Cole County Circuit Court’s May 2012 decision.
Ameren Missouri’s FAC calculation for the period from October 1, 2009, to beMay 31, 2011, excluded all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda’s load caused by a severe ice storm in January 2009, similar to the FAC calculation for the period from March 1, 2009, to September 30, 2009. The MoPSC issued an order in 2013.
In February 2012,July 2013, which was similar to the MoPSC staff issuedMoPSC's April 2011 order, as a result of which Ameren Missouri recorded a pretax charge to earnings of $26 million, including $1 million for interest, in 2013 for its FAC review reportestimated obligation to refund to Ameren Missouri’s electric customers the earnings associated with these sales previously recognized by Ameren Missouri for the period from October 1, 2009, to May 31, 2011. In its report, the MoPSC staff asked the MoPSC to direct Ameren Missouri to refund to customersrecorded the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. Missouri law does not impose a specific deadline by which the MoPSC must complete its prudence reviews. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for“Operating Revenues – Electric” and the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probablerelated interest to “Interest Charges” with a corresponding offset to “Current
regulatory liabilities.” No similar revenues were excluded from FAC calculations after May 2011.
Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer as a regulatory asset, fixed costs totaling $36$36 million that were not previously recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for
potential recovery in a future electric rate case. We cannot predictIn November 2013, the ultimate outcome of these regulatory or judicial proceedings. If the courts ultimately rule in favor ofMoPSC issued an order approving Ameren Missouri's position regarding the classification of the long-term partial requirements sales,request for an accounting authority order. Ameren Missouri would notwill seek to recover from customers the sum that would be covered bythese fixed costs in its next electric rate case. In February 2014, MIEC filed an appeal of the accounting authority order if it is granted.to the Missouri Court of Appeals, Western District.
Regional Transmission Organization2012 Electric Rate Order
Ameren Missouri is a transmission-owning member of MISO. In AprilDecember 2012, the MoPSC authorizedissued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million. The revenue increase was based on a 9.8% return on equity, a capital structure composed of 52.3% common equity, and a rate base of $6.8 billion. Rate changes consistent with the order became effective on January 2, 2013. In January 2013, Ameren Missouri appealed the order with respect to the amount of property taxes included in the order to the Missouri Court of Appeals, Western District. Later in 2013, Ameren Missouri withdrew this appeal. In February 2013, the MoOPC, MIEC, and other parties filed separate appeals to the Missouri Court of Appeals, Western District, relating to the order's treatment of transmission costs in the FAC. In October 2013, the Missouri Court of Appeals, Western District, upheld the order. MoOPC, MIEC, and other parties filed a request to transfer their appeal to the Missouri Supreme Court, which was subsequently denied.
MEEIA Order
The MoPSC's December 2012 electric rate order approved Ameren Missouri's continued conditional MISO participation through May 2016, including the condition thatimplementation of MEEIA megawatthour savings targets, energy efficiency programs, and associated cost recovery mechanisms and incentive awards. A MEEIA rider allows Ameren Missouri later file a further study withto collect from or refund to customers any annual difference in the MoPSC that evaluatesactual amounts incurred and the projected amounts collected from customers for the MEEIA program costs and benefitsits projected lost revenues.
In addition to the program costs and lost revenues discussed above, the terms of Ameren Missouri's continued participationMoPSC-approved MEEIA programs offer an incentive award that would allow Ameren Missouri to earn additional revenues by achieving certain energy efficiency goals, including approximately $19 million if 100% of its energy efficiency goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri's energy savings exceed those goals. Ameren Missouri must achieve at least 70% of its energy efficiency goals before it earns any incentive award. The recovery of an incentive award from customers, if the energy efficiency goals are achieved, is expected in MISO, as2017 through the above-mentioned rider.
Rate Design and Earnings Complaint Cases
On February 13, 2014, Ameren Missouri’s largest customer, Noranda, and 37 residential customers filed an earnings complaint case and a rate design complaint case with the MoPSC. In the earnings complaint case, Noranda and the residential customers asserted that Ameren Missouri’s electric delivery service business is earning more than the 9.8% return on equity authorized in the MoPSC's December 2012 electric rate order and requested the MoPSC to approve a reduction of the authorized return on equity to 9.4%. The rate design complaint case seeks to reduce Noranda’s electricity cost with an offsetting increase in electricity cost for Ameren Missouri’s other customers. The rate design complaint case asks the MoPSC to expedite its decision and grant relief by August 1, 2014.
The MoPSC has ordered Ameren Missouri to file a response to these two complaints by March 17, 2014. The MoPSC has no time requirement by which it has periodically done sincemust issue an order in these cases. Ameren Missouri opposes both requests filed by Noranda and the residential customers and will vigorously defend itself.
Illinois
IEIMA
Under the provisions of the IEIMA, Ameren Illinois' electric delivery service rates effective for customers' billings in 2013 were subject to an annual revenue requirement reconciliation to its MISO participation began in 2003.actual 2013 costs. The next cost benefit study is required to2013 revenue requirement reconciliation will be filed with the MoPSCICC in November2014. The approved annual revenue requirement reconciliation adjustment relating to 2013 will be reflected in customer rates beginning in January 2015.
Illinois
IEIMA
Throughout the year, Ameren Illinois' initial filingIllinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to participateoperating revenues for any differences between the revenue requirement in effect for that year and its estimate of the probable increase or decrease in the performancerevenue requirement expected to ultimately be approved by the ICC based formula ratemaking processon that year's actual costs incurred. As of December 31, 2013, Ameren Illinois recorded a $65 million regulatory asset to reflect its expected 2013 revenue requirement reconciliation adjustment, which will be recovered from customers in 2015. Ameren Illinois also recorded a regulatory liability of $65 million and $55 million as of December 31, 2013, and December 31, 2012, respectively, to reflect its 2012 revenue requirement reconciliation adjustment, with interest, which will be refunded to customers in 2014.
In May 2013, Illinois enacted into law certain amendments to the IEIMA that modified its implementation. The law clarified that the IEIMA requires that the year-end rate base must be used to calculate the revenue requirement reconciliation and that the interest applied to the revenue requirement reconciliation and return on equity collar adjustments must be equal to a company's weighted-average return calculated under the IEIMA was based on 2010 recoverable costs and expected net plant additions for 2011 and 2012. formula rate.
In September 2012, the ICC issued an order in Ameren Illinois' initial filing under the IEIMA's performance-based formula rate framework, which Ameren Illinois appealed to the Appellate
Court of the Fourth District of Illinois. In December 2012, the ICC issued an order in Ameren Illinois' update filing approving an Ameren Illinois electric delivery service revenue requirement of $779765 million, which was a $55 million decrease from the electric delivery service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The rates became effective on October 19, 2012, and were effective through the end of 2012. In October 2012, Ameren Illinois filed an appeal of the ICC's initial filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes that the ICC has incorrectly implemented the IEIMA by using an average rate base as opposed to a year-end rate base in setting rates, through its treatment of accumulated deferred income taxes, and through the method it used for calculating the equity portion of Ameren Illinois' capital structure and the method for calculating interest on the revenue requirement reconciliation and return on equity collar. The ICC's September 2012 order jeopardizes Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is slowing IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to effectuate with the law. Although Ameren Illinois intends to meet its IEIMA capital spending requirements, it is proceeding on a slower investment schedule than previously contemplated.
In April 2012, Ameren Illinois submitted to the ICC an update filing under IEIMA based on 2011 recoverable costs and expected net plant additions forin 2012. In December 2012, the ICC issued an order approving an Ameren Illinois electricThe delivery service revenue requirement of $764 million, which is a $15
million decrease in the revenue requirement allowed in the ICC initial filing order. The rates became effective on January 1, 2013, and will be effective through the end of 2013. In January 2013, Ameren Illinois filed an appeal of the ICC's update filing order to the Appellate Court of the Fourth District of Illinois. A decision byBoth orders were consolidated for appeal with the primary issues being the treatment of accumulated deferred income taxes and vacation obligations as well as the calculation of Ameren Illinois' capital structure. In December 2013, the appellate court is expected in 2013.
rendered its decision upholding the ICC's September and December 2012 orders. Ameren Illinois will submitexpects to file an appeal to the Illinois Supreme Court in March 2014.
In December 2013, the ICC during the second quarter of 2013,issued an order in Ameren Illinois' annual update filing, which was based on 2012 recoverable costs and expected net plant additions for 2013, which will determine rates that are effective during 2014.
approving an Ameren Illinois' 2012Illinois electric delivery service revenues were based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated underrevenue requirement of $788 million, before consideration of the IEIMA's performance-based formula ratemaking framework. The 2012 revenue requirement underreconciliation refund. The ICC order resulted in a net $45 million decrease in Ameren Illinois' electric delivery service revenue requirement. The calculation included a refund to customers of the IEIMA's formula ratemaking framework was lower than the2012 revenue requirement reconciliation of $68 million, which included an estimate for interest through the end of 2014. However, this refund is partially offset by an annual revenue requirement increase of $23 million primarily due to higher recoverable costs in both2012 compared to 2011. The ICC order establishes rates for all of 2014. In January 2014, Ameren Illinois filed a request for rehearing with the ICC's 2010ICC regarding the electric delivery service rate order, which the ICC denied. In February 2014, Ameren Illinois filed an appeal with the Appellate Court of the Fourth District of Illinois regarding the calculation of its capital structure and the ICC's September 2012 ordertreatment of accumulated deferred income taxes related to the transfer of former Ameren Illinois' initial IEIMA filing.Missouri assets in Illinois to Ameren Illinois.
In the December 2013 order, the ICC disallowed, in part, the recovery from customers of the debt premium costs paid by Ameren Illinois for a tender offer in August 2012 to repurchase outstanding senior secured notes. At the time of the tender offer, Ameren Illinois recorded this loss on the reacquired debt as a regulatory asset. As a result of the ICC order, Ameren and Ameren Illinois each recorded in 2013 a $55pretax charge to earnings of $15 million regulatory liability relating to the partial disallowance of the premium costs. This charge was recorded in the statement of income for Ameren and Ameren Illinois as “Interest charges” with a corresponding decrease in electric revenues to represent its estimate of the probable decrease in electric delivery service revenues expected to be approved by the ICC in December 2013 to provide Ameren Illinois recovery of all prudently and reasonably incurred costs and an earned rate of return on common equity for 2012. Any decrease in electric delivery service revenues approved by the ICC in December 2013 will be refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA.
In December 2012, the ICC approved Ameren Illinois' advanced metering infrastructure deployment plan, which outlines how Ameren Illinois will comply with the IEIMA requirement to spend $360 million on smart grid assets over ten years on a cost-beneficial basis to its electric customers. The plan targets the second quarter of 2014 to begin installation of smart meters.“Regulatory assets.”
2013 Natural Gas Delivery Service Rate CaseOrder
On January 25,In December 2013, Ameren Illinois filed a request with the ICC toissued a rate order that approved an increase its annualin revenues for natural gas delivery service by $50 million.of $32 million. The requestrevenue increase was based on a 10.4%9.1% return on equity, a capital structure composed of 51.8%51.7% common equity, and a rate base of $1.1 billion.$1.1 billion. The rate order was based on a 2014 future test year. The rate changes became effective January 1, 2014. In an attempt to reduce regulatory lag,January 2014, Ameren Illinois is usingfiled a future test year of 2014 in this proceeding.request
Also in its filing, Ameren Illinois is requesting an increase in the percentage of costs to be recovered through a fixed non-volumetric customer charge from 80% to 85%
for all residential customers and most commercial customers.
A decision byrehearing with the ICC in this proceeding is required by December 2013. Ameren Illinois cannot predictregarding the level of anynatural gas delivery service rate changesorder, which the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable
denied. Ameren Illinois expects to file an appeal of the ICC's order in March 2014.
Similar to the December 2013 electric rate order discussed above, this natural gas rate order included a partial disallowance relating to the August 2012 costs for the tender offer to repurchase outstanding senior secured notes. The pretax loss of $15 million discussed above includes the impact of both the December 2013 ICC electric and natural gas delivery service rate orders.
Natural Gas Consumer, Safety and Reliability Act
In July 2013, Illinois enacted the Natural Gas Consumer, Safety and Reliability Act, which encourages Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provides additional ICC oversight of natural gas utility performance. The law allows natural gas utilities the option to file for, and requires the ICC to approve, a rate rider mechanism to recover costs of certain natural gas infrastructure investments made between rate cases. The law does not require a minimum level of investment. Ameren Illinois expects to begin including investments under this regulatory framework in 2015. Ameren Illinois' decision to accelerate modernization of its costs and earn a reasonablenatural gas infrastructure under this regulatory framework is dependent upon multiple considerations, including the allowed return on its investments when the rate changes go into effect. equity under this framework compared with other Ameren and Ameren Illinois investment options.
ATXI Transmission Project
ATXI's Illinois Rivers project is a MISO-approved project that involves buildingto build a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri.Missouri at an estimated cost of $1.1 billion. In 2012, ATXI made a filing withAugust 2013, the ICC requestinggranted a certificate of public convenience and necessity and project approval. A decision is expected by the ICC in 2013. A certificateapproved seven of public convenience and necessity is required before ATXI can proceed with right-of-way acquisition.
Federal
Electric Transmission Investment
In May 2011, FERC approved transmission rate incentives for the Illinois Rivers project, which is being developed by ATXI. In December 2011, MISO approved the Illinois Rivers project as well as the Spoon River and Mark Twain projects. Thea total investment in these three MISO-approved projects is expected to be more than $1.3 billion between 2013 to 2019. These projects are primarily located in Illinois and Missouri.
In February 2012, FERC approved ATXI's request for a forward-looking rate calculation with an annual revenue requirement reconciliation, as well as ATXI's request for implementationof nine sections of the incentives FERC approved in its May 2011 orderroute and three of the proposed nine substations for the Illinois Rivers project. The ICC order indicated the project is necessary to address transmission and reliability needs in an efficient and equitable manner and that the project will benefit the development of a competitive electricity market. The order also indicated that ATXI is capable of constructing, managing and financing the project. In November 2012, FERCOctober 2013, the ICC granted ATXI's request for a rehearing to consider additional evidence regarding the two segments of the route and six substations that were not approved, transmission rate incentivesas well as the requests for rehearing of certain other parties regarding two of the approved segments of the route. In February 2014, the ICC issued a final order on rehearing approving the remaining substations and routes for the Spoon River project and the Mark TwainIllinois Rivers project. FERC also approved a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois' electric transmission business.
Federal
2011 Wholesale Distribution Rate Case
In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers by $11 million.customers. These wholesale distribution revenues are
treated as a deduction from Ameren Illinois' revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois has reached an agreement with four of its nine wholesale customers. FERC has approved these settlement agreements, and any refund obligations related thereto have been made. The impasse with the remaining five wholesale customers has resulted in FERC litigation. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. AThe timing of a FERC decision is expected in 2013.uncertain. In accordance with the administrative law judge's initial decision, Ameren and Ameren Illinois each has recordedhave both included on their balance sheets in "Current regulatory liabilities" an estimate of $13 million and $8 million in “Current regulatory liabilities” on its balance sheet as ofDecember 31, 2013, and December 31, 2012, respectively, for its estimate of the refund due to wholesale customers relating to billings for the period from March 2011 through December 2012 based on the administrative law judge's initial decision.2013.
Ameren Illinois Electric Transmission Rate Refund
OnIn July 19, 2012, FERC issued an order approving Ameren Illinois' accounting for the Ameren Illinois Merger, which is discussed in Note 16 - 2010 Corporate Reorganization. As part of this order, FERC concludedconcluding that Ameren Illinois improperly included acquisition premiums, particularlyprimarily goodwill, in determining itsthe common equity used in its electric transmission formula rate, and thereby inappropriately recoveringrecovered a higher return on rate baseamount from its electric transmission customers. The order required Ameren Illinois to make refunds to customers for such improperly included amounts. In August 2012, Ameren Illinois filed a request for a rehearing of this order. It is unknown when FERC will rule on Ameren's rehearing request, as it is under no deadline to do so. After reviewing the FERC order and its calculation of the impact on electric transmission formula rates,
Ameren Illinois submitted a refund report in November 2012 and concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund iswas warranted. In June 2013, FERC issued an order that rejected Ameren Illinois' November 2012 refund report and provided guidance as to the filing of a new refund report. In July 2013, Ameren Illinois filed a revised refund report based on the guidance provided in the June 2013 order, as well as a request for a rehearing of that order. Ameren Illinois' July 2013 refund report also concluded that no refund was warranted. Ameren Illinois estimated the maximum pretax charge to earnings for this possible refund obligation through December 31, 2013, would be $15 million, before interest charges. If Ameren Illinois were to determine that a refund to its electric transmission customers is probable, a charge to earnings would be recorded recorded for the refund in the period in which that determination was made and the amount could be estimated.made.
FERC Order - MISO ChargesComplaint Case
Ameren Missouri and Ameren Illinois,In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed return on common equity, as well as othera limit on the common equity ratio, under the MISO participants, have filed complaints with FERC with respecttariff. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also
result in a refund for transmission service revenues earned after the FERC’s March 2007 order involvingfiling of the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. Subsequently,complaint case in November 2013. FERC has issued a series of orders related to the applicability and the implementation of the order, which in some cases have conflicted with previous orders.
In May 2009, FERC changed the effective date for refunds such that certain operational costs would be allocated among MISO market participants beginning November 2008, instead of August 2007. In June 2009, Ameren Missouri and Ameren Illinois filed a request for rehearing. The rehearing request is pending.
In June 2009, FERCnot issued an order dismissing rehearing requests of a November 2008 orderin this case, and waiving refunds of amounts billed that were included in the MISO charge,it is under the assumption that there was a rate mismatch for the period April 2006 through November 2007.no deadline to do so. Ameren Missouri and Ameren Illinois filed a request for rehearing in July 2009. This rehearing request is pending.
Ameren Missouri and Ameren Illinois do not believe that the ultimate resolution of these proceedingsable to predict when or how FERC will have a material effectrule on their results of operations, financial position, or liquidity.this complaint case.
Ameren Missouri Power Purchase Agreement with Entergy
Beginning in 2005, FERC issued a series of orders addressing a complaint filed in 2001 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 Ameren Missouri in 2007 for
additional charges under a 165-megawatt power purchase agreement, and Ameren Missouri paid those charges. Additional charges continued during the remainder of the term of the power purchase agreement, which expired August 31, 2009. In May 2012, FERC issued an order upholding its January 2010 rulingstating that Entergy should not have included additional charges to Ameren Missouri under the power purchase agreement. Pursuant to the order, in June 2012, Entergy paid Ameren Missouri $31 million, with $24 million recorded as a reduction to “Purchased power” expense and $5 million for interest recorded as “Miscellaneous income” in the statement of income, and theincome. The remaining $2 million was recorded as an offset to the FAC under-recovered regulatory asset for the amount refundable to customers. The amount of the Entergy refund recorded to the FAC regulatory asset related to the period when the FAC was effective and,effective; therefore, such costs were previously included in customer rates. As noted above, the MoPSC, in its December 2012 electric rate order, confirmed Ameren Missouri could retain the portion of the refund received from Entergy that related to the period prior to the implementation of the FAC. In July 2012, Entergy filed an appeal of FERC's January 2010 and May 2012 orders to the United States Court of Appeals for the District of Columbia.Columbia Circuit, which was subsequently dismissed on a procedural issue. In DecemberNovember 2013, Entergy refiled the appeal of FERC's May 2012 order with the United States Court of Appeals dismissedfor the District of Columbia Circuit. Ameren is not able to predict when or how the court will rule on Entergy's appeal as premature because an Entergy motion seeking clarification or rehearing of the May 2012 order remains pending before FERC. It is unknown when FERC may act on the pending Entergy motion.appeal.
The LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy Services, Inc. to the United States Court of Appeals for the District of Columbia.Columbia Circuit. In April 2008, that court ordered further FERC proceedings regarding LPSC’s complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on Ameren Missouri. Ameren Missouri is unable to predict when or how FERC will respond to the court’s decisions. Ameren Missouri estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. Ameren Missouri believes that the likelihood of incurring any expense is not probable, and therefore no liability has been recorded as of December 31, 2012.2013.
Combined Construction and Operating License
In 2008, Ameren Missouri filed an application with the NRC for a COL for a new nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a new nuclear unit at its existing Missouri nuclear energy center site, and the NRC suspended review of the COL application.
In March 2012, the DOE announced the availability of investment funds for the design, engineering, manufacturing, and sale of American-made small modular nuclear reactors. In April 2012, Ameren Missouri entered into an exclusive agreement with
Westinghouse to exclusively support Westinghouse's application for the first installment of DOE's small modular nuclear reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. In November 2012, the DOE awarded investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that additional investment funds would be awarded during 2013. Westinghouse continues to pursue investment funds from the DOE.
If Westinghouse is awarded DOE's small modular reactor investment funds, Ameren Missouri will seek a COL from the NRC for a Westinghouse small modular reactor or multiple reactors at its Callaway energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear energy center at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC doeswould not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it doeswould preserve the option to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years. In November 2012, the DOE awarded the first installment of investment funds for only 40one years.small modular reactor design, which was not the Westinghouse design. The DOE stated that a second installment of investment funds would be awarded during 2013. In December 2013, the DOE did not award Westinghouse the second installment of investment funds. Ameren Missouri's
agreement to exclusively support Westinghouse's application expired in January 2014.
Ameren Missouri estimatesestimated the total cost that would be required to obtain the small modular reactor COL willto be in the range of $80 million to $100 million. As of December 31, 2013, Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal due to several factors, including the company'shad capitalized investments in new nuclear energy center development of $69 million as of December 31, 2012, the DOE investment funds that would help support the COL application, and Ameren Missouri's agreement with Westinghouse. If the DOE does not approve Westinghouse's application for the small modular reactor investment funds,development of a new nuclear energy center. Ameren Missouri is not obligatedcurrently evaluating all potential nuclear technologies in order to pursue a COLmaintain an option for nuclear power in the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse.future.
All of Ameren Missouri's costs incurred to license additionalcapitalized investments for the development of a new nuclear generation at the Callaway siteenergy center will remain capitalized while management pursues options to maximize the value of its investment. If efforts to license additional nuclear generation are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination wasis made.
Pumped-storage Hydroelectric Energy Center Relicensing
In June 2008, Ameren Missouri filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric energy center for another 40 years. The existing FERC license expired on June 30, 2010. OnIn July 2, 2010, Ameren Missouri received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. FERC is reviewing the relicensing application. A FERC order is expected in 2013 or 2014. Ameren Missouri cannot predict the ultimate outcome of FERC's review of the application.
Regulatory Assets and Liabilities
In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, Ameren Missouri and Ameren Illinois defer certain costs as regulatory assets pursuant to actions of regulators or based on the expected ability to recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts as regulatory liabilities because of actions of regulators or because of the expectation that such amounts will be returned to customers in future rates. The following table presents Ameren’s, Ameren Missouri’s and Ameren Illinois’ regulatory assets and regulatory liabilities at December 31, 2012,2013, and 2011:2012:
| |
| | 2012 | | 2011 | | 2013 | | 2012 |
| | Ameren | | Ameren Missouri | | Ameren Illinois | | Ameren | | Ameren Missouri | | Ameren Illinois | | Ameren Missouri | | Ameren Illinois | | Ameren | | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Current regulatory assets: | | | | | | | | | | | | | | | | | | | | | | | | | |
Under-recovered FAC(c)(b) | | $ | 145 |
| | $ | 145 |
| | $ | — |
| | $ | 83 |
| | $ | 83 |
| | $ | — |
| | $ | 104 |
| | $ | — |
| | $ | 104 |
| | | $ | 145 |
| | $ | — |
| | $ | 145 |
|
Under-recovered Illinois electric power costs(d)(c) | | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
| | — |
| | 1 |
| | 1 |
| | | — |
| | — |
| | — |
|
Under-recovered PGA(d)(c) | | 12 |
| | 5 |
| | 7 |
| | 8 |
| | 5 |
| | 3 |
| | — |
| | 1 |
| | 1 |
| | | 5 |
| | 7 |
| | 12 |
|
MTM derivative losses(e)(d) | | 90 |
|
| 13 |
|
| 77 |
| | 120 |
| (a) | 21 |
| | 299 |
| | 14 |
|
| 36 |
| | 50 |
| | | 13 |
| | 77 |
| | 90 |
|
| Total current regulatory assets | | $ | 247 |
| | $ | 163 |
| | $ | 84 |
| | $ | 215 |
| | $ | 109 |
| | $ | 306 |
| | $ | 118 |
| | $ | 38 |
| | $ | 156 |
| | | $ | 163 |
| | $ | 84 |
| | $ | 247 |
|
| Noncurrent regulatory assets: | | | | | | | | | | | | | | | | | | | | | | | | | |
Pension and postretirement benefit costs(f)(e) | | $ | 772 |
| | $ | 348 |
| | $ | 424 |
| | $ | 878 |
| | $ | 382 |
| | $ | 496 |
| | $ | 44 |
| | $ | 140 |
| | $ | 184 |
| | | $ | 348 |
| | $ | 424 |
| | $ | 772 |
|
Income taxes(g)(f) | | 235 |
| | 231 |
| | 4 |
| | 239 |
| | 234 |
| | 5 |
| | 230 |
| | 7 |
| | 237 |
| | | 231 |
| | 4 |
| | 235 |
|
Asset retirement obligations(h)(g) | | 5 |
| | — |
| | 5 |
| | 6 |
| | — |
| | 6 |
| | — |
| | 5 |
| | 5 |
| | | — |
| | 5 |
| | 5 |
|
Callaway costs(i)(h) | | 44 |
| | 44 |
| | — |
| | 48 |
| | 48 |
| | — |
| | 40 |
| | — |
| | 40 |
| | | 44 |
| | — |
| | 44 |
|
Unamortized loss on reacquired debt(j)(i) | | 181 |
| | 81 |
| | 100 |
| | 47 |
| | 21 |
| | 26 |
| | 77 |
| | 74 |
| | 151 |
| | | 81 |
| | 100 |
| | 181 |
|
Recoverable costs - contaminated facilities(k) | | 248 |
| | — |
| | 248 |
| | 102 |
| | — |
| | 102 |
| |
Recoverable costs – contaminated facilities(j) | | | — |
| | 271 |
| | 271 |
| | | — |
| | 248 |
| | 248 |
|
MTM derivative losses(e)(d) | | 135 |
|
| 7 |
|
| 128 |
|
| 100 |
|
| 13 |
| | 87 |
| | 8 |
|
| 118 |
| | 126 |
|
|
| 7 |
| | 128 |
| | 135 |
|
SO2 emission allowances sale tracker(l) | | 2 |
| | 2 |
| | — |
| | 6 |
| | 6 |
| | — |
| |
Storm costs(m) | | 9 |
| | 9 |
| | — |
| | 16 |
| | 16 |
| | — |
| |
Demand-side costs(b)(n) | | 73 |
| | 73 |
| | — |
| | 70 |
| | 70 |
| | — |
| |
Reserve for workers’ compensation liabilities(o) | | 12 |
| | 6 |
| | 6 |
| | 13 |
| | 7 |
| | 6 |
| |
Credit facilities fees(p) | | 6 |
| | 6 |
| | — |
| | 10 |
| | 10 |
| | — |
| |
Employee separation costs(q) | | 2 |
| | 1 |
| | 1 |
| | 6 |
| | 3 |
| | 3 |
| |
Common stock issuance costs(r) | | 7 |
| | 7 |
| | — |
| | 10 |
| | 10 |
| | — |
| |
Construction accounting for pollution control equipment(b)(s) | | 23 |
| | 23 |
| | — |
| | 25 |
| | 25 |
| | — |
| |
Other(t) | | 32 |
| | 14 |
| | 18 |
| | 27 |
| | 10 |
| | 17 |
| |
Storm costs(k) | | | 5 |
| | 3 |
| | 8 |
| | | 9 |
| | — |
| | 9 |
|
Demand-side costs before MEEIA implementation(a)(l) | | | 58 |
| | — |
| | 58 |
| | | 73 |
| | — |
| | 73 |
|
Reserve for workers’ compensation liabilities(m) | | | 6 |
| | 6 |
| | 12 |
| | | 6 |
| | 6 |
| | 12 |
|
Credit facilities fees(n) | | | 5 |
| | — |
| | 5 |
| | | 6 |
| | — |
| | 6 |
|
Common stock issuance costs(o) | | | 4 |
| | — |
| | 4 |
| | | 7 |
| | — |
| | 7 |
|
Construction accounting for pollution control equipment(a)(p) | | | 22 |
| | — |
| | 22 |
| | | 23 |
| | — |
| | 23 |
|
Solar rebate program(a)(q) | | | 27 |
| | — |
| | 27 |
| | | 5 |
| | — |
| | 5 |
|
IEIMA revenue requirement reconciliation(r) | | | — |
| | 65 |
| | 65 |
| | | — |
| | — |
| | — |
|
Other(s)(t) | | | 8 |
| | 12 |
| | 25 |
| | | 12 |
| | 19 |
| | 31 |
|
| Total noncurrent regulatory assets | | $ | 1,786 |
| | $ | 852 |
| | $ | 934 |
| | $ | 1,603 |
| | $ | 855 |
| | $ | 748 |
| | $ | 534 |
| | $ | 701 |
| | $ | 1,240 |
| | | $ | 852 |
| | $ | 934 |
| | $ | 1,786 |
|
| Current regulatory liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | |
Over-recovered FAC(u)(b) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 26 |
| | | $ | — |
| | $ | — |
| | $ | — |
|
Over-recovered Illinois electric power costs(d)(c) | | 58 |
| | — |
| | 58 |
| | 64 |
| | — |
| | 64 |
| | — |
| | 51 |
| | 51 |
| | | — |
| | 58 |
| | 58 |
|
Over-recovered PGA(d)(c) | | 15 |
| | — |
| | 15 |
| | 9 |
| | — |
| | 9 |
| | 5 |
| | 29 |
| | 34 |
| | | — |
| | 15 |
| | 15 |
|
MTM derivative gains(v) | | 19 |
|
| 18 |
|
| 1 |
|
| 46 |
|
| 45 |
| | 1 |
| |
MTM derivative gains(d) | | | 26 |
| | 1 |
| | 27 |
|
| | 18 |
| | 1 |
| | 19 |
|
Wholesale distribution refund(w)(u) | | 8 |
| | — |
| | 8 |
| | 2 |
| | — |
| | 2 |
| | — |
| | 13 |
| | 13 |
| | | — |
| | 8 |
| | 8 |
|
IEIMA revenue requirement reconciliation(r) | | | — |
| | 65 |
| | 65 |
| | | — |
| | — |
| | — |
|
| Total current regulatory liabilities | | $ | 100 |
| | $ | 18 |
| | $ | 82 |
| | $ | 133 |
| | $ | 57 |
| | $ | 76 |
| | $ | 57 |
| | $ | 159 |
| | $ | 216 |
| | | $ | 18 |
| | $ | 82 |
| | $ | 100 |
|
| Noncurrent regulatory liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | |
Income taxes(x) | | $ | 46 |
| | $ | 42 |
| | $ | 4 |
| | $ | 48 |
| | $ | 44 |
| | $ | 4 |
| |
Removal costs(y) | | 1,347 |
| | 766 |
| | 581 |
| | 1,269 |
| | 719 |
| | 550 |
| |
Asset retirement obligation(h) | | 80 |
| | 80 |
| | — |
| | 29 |
| | 29 |
| | — |
| |
MTM derivative gains(v) | | 2 |
|
| 2 |
|
| — |
|
| 82 |
|
| 4 |
| | 78 |
| |
Bad debt rider(z) | | 12 |
| | — |
| | 12 |
| | 10 |
| | — |
| | 10 |
| |
Pension and postretirement benefit costs tracker(aa) | | 23 |
| | 23 |
| | — |
| | 38 |
| | 38 |
| | — |
| |
Energy efficiency rider(ab) | | 20 |
| | — |
| | 20 |
| | 24 |
| | — |
| | 24 |
| |
IEIMA revenue requirement reconciliation(ac) | | 55 |
| | — |
| | 55 |
| | — |
| | — |
| | — |
| |
Other(ad) | | 4 |
| | 4 |
| | — |
| | 2 |
| | 2 |
| | — |
| |
Income taxes(v) | | | $ | 38 |
| | $ | 3 |
| | $ | 41 |
| | | $ | 42 |
| | $ | 4 |
| | $ | 46 |
|
Removal costs(w) | | | 828 |
| | 610 |
| | 1,438 |
| | | 766 |
| | 581 |
| | 1,347 |
|
Asset retirement obligation(g) | | | 146 |
| | — |
| | 146 |
| | | 80 |
| | — |
| | 80 |
|
MTM derivative gains(d) | | | 1 |
| | — |
| | 1 |
|
| | 2 |
| | — |
| | 2 |
|
Bad debt riders(x) | | | — |
| | 8 |
| | 8 |
| | | — |
| | 12 |
| | 12 |
|
Pension and postretirement benefit costs tracker(y) | | | 15 |
| | — |
| | 15 |
| | | 23 |
| | — |
| | 23 |
|
Energy efficiency riders(z) | | | 3 |
| | 33 |
| | 36 |
| | | — |
| | 20 |
| | 20 |
|
IEIMA revenue requirement reconciliation(r) | | | — |
| | — |
| | — |
| | | — |
| | 55 |
| | 55 |
|
FERC transmission revenue requirement reconciliation(aa) | | | — |
| | 10 |
| | 10 |
| | | — |
| | — |
| | — |
|
Other(ab) | | | 10 |
| | — |
| | 10 |
| | | 4 |
| | — |
| | 4 |
|
| Total noncurrent regulatory liabilities | | $ | 1,589 |
| | $ | 917 |
| | $ | 672 |
| | $ | 1,502 |
| | $ | 836 |
| | $ | 666 |
| | $ | 1,041 |
| | $ | 664 |
| | $ | 1,705 |
| | | $ | 917 |
| | $ | 672 |
| | $ | 1,589 |
|
| |
| (a) | Includes intercompany eliminations. |
| |
(b) | These assets earn a return. |
| |
(c)(b) | Under-recovered or over-recovered fuel costs for periods from June 2010to be recovered through December 2012.the FAC. Specific accumulation periods aggregate the under-recovered or over-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months. |
any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.
| |
(d)(c) | Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral. |
| |
(e)(d) | Deferral of commodity-related derivative MTM losses. The December 31, 2011 balance included the MTM losses on financial contracts entered into by Ameren Illinois with Marketing Company, which expired in December 2012.or gains. See Note 7 – Derivative Financial Instruments for additional information. |
| |
(f)(e) | These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 -– Retirement Benefits for additional information. |
| |
(g)(f) | Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 - Income Taxes for amortization period.This will be recovered over the expected life of the related assets. |
| |
(h)(g) | Recoverable or refundable removal costs for AROs, at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations. |
investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.
| |
(i)(h) | Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the energy center's current operating license, which expires in 2024. |
| |
(j)(i) | Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remainingoriginal lives of the old debt issuances if no new debt was issued. |
| |
(k)(j) | The recoverable portion of accrued environmental site liabilities primarilythat will be collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of actualremediation expenditures. See Note 15 -– Commitments and Contingencies for additional information. |
| |
(l) | A regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order. The MoPSC’s May 2010 electric rate order discontinued any future deferrals under this tracking mechanism. The MoPSC’s December 2012 rate order approved the amortization of these costs through December 2014.
|
| |
(m)(k) | Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. As approved by the December 2012 MoPSC electric rate order, the 2006, 2007, and 2008 storm costs are being amortized through December 2014. As approved by the May 2010 MoPSC electric rate order, the 2009 storm costs are being amortized through June 2015. The Ameren Illinois total includes 2013 storm costs deferred in accordance with the IEIMA. These costs are being amortized over a five-year period beginning in 2013. |
| |
(n)(l) | Demand-side costs incurred prior to implementation of the MEEIA in 2013, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. Costs incurred from May 2008 through September 2008 are being amortized over a 10-year period that began in March 2009. Costs incurred from October 2008 through December 2009 are being amortized over a six-year period that began in July 2010. Costs incurred from January 2010 through February 2011 are being amortized over a six-year period that began in August 2011. Costs incurred from March 2011 through July 2012 are being amortized over a six-year period that began in January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case. |
| |
(o)(m) | Reserve for workers’ compensation claims. The period of recovery will depend on the timing of actual expenditures. |
| |
(p)(n) | Ameren Missouri’s costs incurred to enter into and maintain the 2012 Ameren Missouri Credit Agreement. These costs are being amortized over five years, beginning in November 2012. These costs are being amortized to construction work in progress, which will be subsequently depreciated when assets are placed into service. |
| |
(q) | Costs incurred for voluntary and involuntary separation programs. The 2009 Ameren Missouri-related costs are being amortized over two years, beginning in January 2013, as approved by the December 2012 MoPSC electric rate order. The 2009 Ameren Illinois-related costs are being amortized over three years, beginning in May 2010, as approved by the April 2010 ICC electric and natural gas rate order. |
| |
(r)(o) | The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to recover its portion of Ameren’s September 2009 common stock issuance costs. These costs are being amortized over five years, beginning in July 2010. |
| |
(s)(p) | The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was placedcould be included in customer rates. The amortization of theseThese costs will be amortized over the expected life of the Sioux energy center.center, which is currently through 2033. |
| |
(t)(q) | Costs associated with Ameren Missouri's solar rebate program beginning in August 2012 to fulfill Ameren Missouri's renewable energy portfolio requirement. The amortization period for these costs will be three years, commencing with the next Ameren Missouri electric rate case order. |
| |
| (r) | The asset balance relates to the difference between Ameren Illinois' 2013 revenue requirement calculated under the IEIMA's performance-based formula ratemaking framework, and the revenue requirement included in customer rates for 2013. Subject to ICC approval, this asset will be collected from customers in 2015. The liability balance relates to the difference between Ameren Illinois' 2012 revenue requirement calculated under the IEIMA's performance-based formula ratemaking framework and the revenue requirement included in customer rates for 2012. This liability will be refunded to customers in 2014. |
| |
| (s) | The Ameren Illinois total includes Ameren Illinois Merger integration and optimization costs, which are amortized over four years, beginning in January 2012. The Ameren Illinois total also includes costs related to the 2013 natural gas delivery service rate cases. The 2012 natural gas rate case costs, which are being amortized over a two-year period that began in January 2012. The electric rate case costs for the IEIMA initial rate filing are being amortized over a three-year period that began in January 2012.2014. The Ameren Illinois total also includes a portion of the unamortized debt fair value adjustment recorded upon Ameren's acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007.debt. At Ameren Missouri, the balance primarily includes cost associated with the retirementcost of renewable energy credits and solar rebates to fulfill its renewable energy portfolio requirement. Costs incurred from January 2010 through July 2012 are being amortized over three years, beginning in January 2013. |
| |
| (t) | The amortization periodAmeren total includes $5 million for ATXI's revenue requirement reconciliation adjustments for 2012 and 2013 calculated pursuant to the FERC's electric transmission formula ratemaking framework. These adjustments will be collected from customers in 2014 for the costs incurred after July 2012 will be determinedrevenue requirement reconciliation and in a future Ameren Missouri electric rate case.2015 for the 2013 revenue requirement reconciliation. |
| |
| (u) | Over-recovered fuel costs from March 2009 through September 2009 as ordered by the MoPSC in April 2011. Customer refunds concluded in 2012. Specific accumulation periods aggregate the over-recovered costs over four months, any related adjustments occur over the following four months, and then recovery from customers occurs over the next eight months. |
| |
(v) | Deferral of commodity-related derivative MTM gains. |
| |
(w) | Estimated refund to wholesale electric customers. See 2011 Wholesale Distribution Rate Case above. |
| |
(x)(v) | Unamortized portion of investment tax credit andcredits, federal excess deferred taxes. See Note 13 - Income Taxes for amortization period.taxes, and uncertain tax position tracker. The tracker is being amortized over three years, beginning in January 2013. The unamortized portion of investment tax credit is being amortized over the expected life of the underlying assets. |
| |
(y)(w) | Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations. |
| |
(z)(x) | A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by Ameren Illinois under GAAP and the level of such costs included in electric and natural gas rates. The over-recovery relating to 20102011 was refunded to customers from June 2011 through May 2012. The over-recovery relating to 2011 is being refunded to customers from June 2012 through May 2013. The over-recovery relating to 2012 is being refunded to customers from June 2013 through May 2014. The over-recovery relating to 2013 will be refunded to customers from June 2013 through May 2014. |
| |
(aa)(y) | A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs built into rates. For periods prior to August 2012, the MoPSC's December 2012 electric rate order directed the amortization to occur over five years, beginning in January 2013. For periods after August 2012, the amortization period will be determined in a future Ameren Missouri electric rate case. |
| |
(ab)(z) | AThe Ameren Illinois balance relates its regulatory tracking mechanism that allows Ameren Illinois to recover its electric and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. This over-recovery will be refunded to customers over the following 12 months after the plan year. The Ameren Missouri balance relates to its MEEIA program costs incurred and projected lost revenues compared to the amount previously collected from customers. Beginning in January 2014, a MEEIA rider allows Ameren Missouri to collect from or refund to customers any annual difference in the actual amounts incurred and the projected amounts collected from customers for the MEEIA program costs and its projected lost revenues. Under the MEEIA rider, collections from or refunds to customers occur one year after the program costs and projected lost revenues are incurred. |
| |
(ac)(aa) | The difference between Ameren Illinois' 20122013 revenue requirement reconciliation adjustment calculated underpursuant to the IEIMA's performance-basedFERC's electric transmission formula ratemaking framework, and the revenue requirement included in customer rates for 2012. Subject to ICC approval, thisframework. This liability will be refunded to customers in 2014.2015. |
| |
(ad)(ab) | Balance primarily includes anthe costs of renewable energy credits to fulfill Ameren Missouri's renewable energy portfolio requirement from August 2012 through December 2013, which were less than the amount included in rates. The amortization period for this over-recovery will be determined in a future Ameren Missouri liability relating to its 2010 property tax refund. The MoPSC's December 2012 electric rate order directed a refund to customers over a two-year period, beginning in January 2013.case. |
Ameren Missouri and Ameren Illinois continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are charged to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that payments of regulatory liabilities are no longer probable, the amounts are credited to earnings.
NOTE 3 -– PROPERTY AND PLANT, NET
The following table presents property and plant, net, for each of the Ameren Companies at December 31, 20122013, and 20112012:
| | | | Ameren(a)(b) | | Ameren Missouri(b) | | Ameren Illinois | | Ameren Missouri(a) | | Ameren Illinois | | Other | | Ameren(a)(b) |
| 2013 | | | | | | | | | |
| Property and plant, at original cost: | | | | | | | | | |
| Electric | | | $ | 15,964 |
| | $ | 5,426 |
| | $ | 336 |
| | $ | 21,726 |
|
| Natural gas | | | 413 |
| | 1,562 |
| | — |
| | 1,975 |
|
| | | | 16,377 |
| | 6,988 |
| | 336 |
| | 23,701 |
|
| Less: Accumulated depreciation and amortization | | | 6,766 |
| | 1,627 |
| | 251 |
| | 8,644 |
|
| | | | 9,611 |
| | 5,361 |
| | 85 |
| | 15,057 |
|
| Construction work in progress: | | | | | | | | | |
| Nuclear fuel in process | | | 246 |
| | — |
| | — |
| | 246 |
|
| Other | | | 595 |
| | 228 |
| | 79 |
| | 902 |
|
| Property and plant, net | | | $ | 10,452 |
| | $ | 5,589 |
| | $ | 164 |
| | $ | 16,205 |
|
| 2012 | | | | | | | | | | | | | |
| Property and plant, at original cost: | | | | | | | | | | | | | |
| Electric | $ | 22,055 |
| | $ | 15,638 |
| | $ | 4,985 |
| | $ | 15,638 |
| | $ | 4,985 |
| | $ | 319 |
| | $ | 20,942 |
|
| Natural gas | 1,854 |
| | 393 |
| | 1,461 |
| | 393 |
| | 1,461 |
| | — |
| | 1,854 |
|
| | 23,909 |
| | 16,031 |
| | 6,446 |
| | 16,031 |
| | 6,446 |
| | 319 |
| | 22,796 |
|
| Less: Accumulated depreciation and amortization | 8,823 |
| | 6,614 |
| | 1,495 |
| | 6,614 |
| | 1,495 |
| | 237 |
| | 8,346 |
|
| | 15,086 |
| | 9,417 |
| | 4,951 |
| | 9,417 |
| | 4,951 |
| | 82 |
| | 14,450 |
|
| Construction work in progress: | | | | | | | | | | | | | |
| Nuclear fuel in process | 317 |
| | 317 |
| | — |
| | 317 |
| | — |
| | — |
| | 317 |
|
| Other | 693 |
| | 427 |
| | 101 |
| | 427 |
| | 101 |
| | 53 |
| | 581 |
|
| Property and plant, net | $ | 16,096 |
| | $ | 10,161 |
| | $ | 5,052 |
| | $ | 10,161 |
| | $ | 5,052 |
| | $ | 135 |
| | $ | 15,348 |
|
| 2011 | | | | | | |
| Property and plant, at original cost: | | | | | | |
| Electric | $ | 24,717 |
| | $ | 15,099 |
| | $ | 4,684 |
| |
| Natural gas | 1,751 |
| | 385 |
| | 1,368 |
| |
| | 26,468 |
| | 15,484 |
| | 6,052 |
| |
| Less: Accumulated depreciation and amortization | 9,429 |
| | 6,276 |
| | 1,364 |
| |
| | 17,039 |
| | 9,208 |
| | 4,688 |
| |
| Construction work in progress: | | | | | | |
| Nuclear fuel in process | 255 |
| | 255 |
| | — |
| |
| Other | 833 |
| | 495 |
| | 82 |
| |
| Property and plant, net | $ | 18,127 |
| | $ | 9,958 |
| | $ | 4,770 |
| |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations. |
| |
(b) | Amounts in Ameren and Ameren Missouri include two electric generation CTs under twoseparate capital lease agreements. The gross cumulative asset value of those agreements was $228 million and $229 millionat December 31, 20122013, and $228 million2011, respectively.at December 31, 2012. The total accumulated depreciation associated with the two CTs was $5256 million and $52 million at December 31, 20122013, and 20112012, respectively. In addition, Ameren Missouri has investments in debt securities, which arewere classified as held-to-maturity, related to the two CTs from the city of Bowling Green and Audrain County. As of December 31, 2012,2013, and 2011,2012, the carrying value of these debt securities was $304299 million and $309304 million, respectively. |
See Note 17 - Impairment and Other Charges for information regarding Ameren's noncash long-lived asset impairment charges recognized in 2012.
| |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
The following table provides accrued capital and nuclear fuel expenditures at December 31, 20122013, 20112012, and 20102011, which represent noncash investing activity excluded from the accompanying statements of cash flows:
| | | | Ameren(a) | | Ameren Missouri | | Ameren Illinois | Ameren(a) | | Ameren Missouri | | Ameren Illinois |
| Accrued capital expenditures: | | | | | | |
| 2013 | | $ | 175 |
| | $ | 74 |
| | $ | 86 |
|
| 2012 | $ | 108 |
| | $ | 63 |
| | $ | 37 |
| 107 |
| | 63 |
| | 37 |
|
| 2011 | 107 |
| | 73 |
| | 18 |
| 97 |
| | 73 |
| | 18 |
|
| 2010 | 79 |
| | 53 |
| | 15 |
| |
| Accrued nuclear fuel expenditures: | | | | | | |
| 2013 | | 8 |
| | 8 |
| | (b) |
|
| 2012 | | 8 |
| | 8 |
| | (b) |
|
| 2011 | | 36 |
| | 36 |
| | (b) |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
NOTE 4 -– SHORT-TERM DEBT AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, and drawings under committed bank credit agreements, or commercial paper issuances.
2012 Credit Agreements
On November 14, 2012, Ameren and Ameren Missouri entered into the $1 billion 2012 Missouri Credit Agreement. The 2010 Missouri Credit Agreement was terminated when the 2012 Missouri Credit Agreement when into effect. Also on November 14, 2012, Ameren and Ameren Illinois entered into the
$1.1 billion 2012 Illinois Credit Agreement. The 2010 Illinois Credit Agreement was terminated when the 2012 Illinois Credit Agreement went into effect. These facilities cumulatively provide $2.1 billion of credit through November 14, 2017, which date is inclusive of the Ameren Missouri and Ameren Illinois borrowing sublimit extensions discussed below of the maturity date to November 14, 2017, and which may be extended with the agreement of the lenders, subject to the terms of such agreements, for two additional one-year periods. The facilities currently include 24 international, national, and regional lenders, with no lender providing more than $125 million of credit in aggregate.
In addition, the 2010 Genco Credit Agreement, under which Ameren was a borrower, was not renewed and was terminated contemporaneously with the effectiveness of the 2012 Credit Agreements.
The obligations of each borrower under the respective 2012 Credit Agreements to which it is a party are several and not joint, and, except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective 2012 Credit Agreements are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum aggregate amount available to each borrower under each facility is shown in the following table (such amount being such borrower's "Borrowing Sublimit"): | | | | 2012 Missouri Credit Agreement | 2012 Illinois Credit Agreement | | 2012 Missouri Credit Agreement | 2012 Illinois Credit Agreement |
| Ameren | $ | 500 |
| $ | 300 |
| $ | 500 |
| $ | 300 |
|
| Ameren Missouri | 800 |
| (a) |
| | 800 |
| (a) |
|
| Ameren Illinois | (a) |
| $ | 800 |
| | (a) |
| 800 |
|
Ameren has the option to seek additional commitments from existing or new lenders to increase the total facility size of the 2012 Credit Agreements up to the followinga maximum amounts:amount of $1.2 billion for the 2012 Missouri Credit Agreement - $1.2 billion; and 2012 Illinois Credit Agreement - $1.3 billion. Each of for the 2012 Illinois Credit Agreement. The 2012 Credit Agreements, will mature and expire with respect to Ameren on November 14, 2017, unless extended as described above.well as the Borrowing Sublimits of Ameren Missouri and Ameren Illinois under the applicable 2012 Credit AgreementsMissouri, will mature and expire on November 13, 2013,14, 2017. The Borrowing Sublimit of Ameren Illinois will mature and expire on September 30, 2014, subject to extension thereof on a 364-day basis as requested by the borrower and approved by the lenders, or for a longer period upon notice by the borrower of receipt of any and all required federal or state regulatory approvals, as permitted under the 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement,credit agreement, but in no event later than November 14, 2017. Ameren Missouri andIn October 2013, Ameren Illinois intend to seekfiled a petition seeking state regulatory approval necessary to extend the maturity datesdate of their respectiveits Borrowing Sublimit under the 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement to November 14, 2017. If and when such regulatory approvals areapproval is received, no lender approval will be required to effect the extensions.extension. The principal amount of each revolving loan owed by a
borrower under any of the 2012 Credit Agreements to which it is a party will be due and
payable no later than the final maturity date relating to such borrower under such 2012 Credit Agreements.
The obligations of all borrowers under the 2012 Credit Agreements are unsecured. Loans are available on a revolving basis under each of the 2012 Credit Agreements andAgreements. Funds borrowed may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates on such loans will be the alternate base rate ("ABR") plus the margin applicable to the particular borrower and/or the Eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by the borrower's long-term unsecured credit ratings or, if no such ratings are then in effect, the borrower's corporate/issuer ratings then in effect. Letters of credit in an aggregate undrawn face amount not to exceed 25% of the applicable aggregate commitment under the respective 2012 Credit Agreements are also available for issuance for the account of the borrowers thereunder (but within the $2.1 billion overall combined facility borrowing limitations of the 2012 Credit Agreements).
The borrowers will use the proceeds from any borrowings under the 2012 Credit Agreements for general corporate purposes, including working capital, commercial paper liquidity support, loan funding under the Ameren money pool arrangements or other short-term intercompany loan arrangements, or paying fees and expenses incurred in connection with the 2012 Credit Agreements.
The 2012 Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren's $500 million commercial paper program and Ameren Missouri's $500 million commercial paper program and Ameren Illinois' $500 million commercial paper program. AnyEither of the 2012 Credit Agreements are available to Ameren to support borrowingsissuances under Ameren's commercial paper program, subject to borrowing sublimits. The 2012 Missouri Credit Agreement is available to support issuances under Ameren Missouri's commercial paper program, and the 2012 Illinois Credit Agreement is available to support issuances underprogram. Ameren Illinois' $500 millioncommercial paper program.program, under which no commercial paper was ever issued, was terminated in 2013. As of December 31, 20122013, based on commercial paper outstanding and letters of credit issued under the 2012 Credit Agreements, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively, at December 31, 2012,2013, was $2.091.7 billion.
The following table summarizes the borrowing activity and relevant interest rates under the 2010 Missouri Credit Agreement, which terminated on November 14, 2012, for the years ended December 31, 2012, and 2011 and excludes issued letters of credit. Ameren, Ameren Missouri, and Ameren Illinois did not borrow under the 2012 Credit Agreements from November 14, 2012, through December 31, 2012.
|
| | | | | | | | | | | |
| 2010 Missouri Credit Agreement ($800 million) (Terminated) | Ameren (Parent) | | Ameren Missouri | | Total |
| 2012 | | | | | |
Average daily borrowings outstanding during 2012(a) | $ | — |
| | $ | 1 |
| | $ | 1 |
|
| Outstanding credit facility borrowings at period end | — |
| | — |
| | — |
|
Weighted-average interest rate during 2012(a) | — | % | | 4.15 | % | | 4.15 | % |
Peak credit facility borrowings during 2012(a) | $ | — |
| | $ | 50 |
| | $ | 50 |
|
| Peak interest rate during 2012 | — | % | | 4.15 | % | | 4.15 | % |
| 2011 | | | | | |
| Average daily borrowings outstanding during 2011 | $ | 105 |
| | $ | — |
| | $ | 105 |
|
| Outstanding credit facility borrowings at period end | — |
| | — |
| | — |
|
| Weighted-average interest rate during 2011 | 2.30 | % | | — |
| | 2.30 | % |
| Peak credit facility borrowings during 2011 | $ | 340 |
| | $ | — |
| | $ | 340 |
|
| Peak interest rate during 2011 | 4.30 | % | | — |
| | 4.30 | % |
| |
(a) | Calculated through termination date. |
Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the years ended December 31, 2012, and 2011, respectively.
Commercial Paper
At December 31, 2012, Ameren did not have any commercial paper outstanding. At December 31, 2011, Ameren had $148 million of commercial paper outstanding. Duringfor the years ended December 31, 20122013, and 20112012, Ameren had average daily.
Commercial Paper
The following table summarizes the borrowing activity and relevant interest rates under Ameren's commercial paper balances outstanding of $49 million and $311 million with a weighted-average interest rate of 0.92% and 0.87%, respectively. The peak amounts of short-term commercial paper outstanding duringprogram, for the years ended December 31, 20122013, and 2011, were $229 million and $435 million, respectively. The peak interest rate during the years ended December 31, 2012, and :2011, was 1.25% and 1.46%, respectively.
|
| | | | | | | | |
| | | 2013 | | 2012 |
| Average daily borrowings outstanding | | $ | 54 |
| | $ | 49 |
|
| Outstanding borrowings at period-end | | 368 |
| | — |
|
| Weighted-average interest rate | | 0.56 | % | | 0.92 | % |
| Peak borrowings during period | | $ | 368 |
| | $ | 229 |
|
| Peak interest rate | | 0.85 | % | | 1.25 | % |
Indebtedness Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants.
The 2012 Credit Agreements contain conditions to borrowings and issuances of letters of credit, similar to those contained in the 2010 Credit Agreements, 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 the absence of any notice of any violation, liability or requirement under any environmental laws that could have a material adverse effect), and obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2012 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation.
The 2012 Credit Agreements also contain nonfinancial covenants, similar to those contained in the 2010 Credit Agreements, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The 2012 Credit Agreements require each of Ameren, Ameren Missouri and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of December 31, 20122013, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 51%48%, 48%47% and 43%44%, for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, under the 2012 Illinois Credit Agreement and, by virtue of the cross-default provisions of the 2012 Missouri Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1.0, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2012 Illinois Credit Agreement. Ameren’s ratio as of December 31, 20122013, was 5.05.3 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement.
The 2012 Credit Agreements contain default provisions. The default provisions in the 2012 Credit Agreementsthat apply separately to each borrower, provided, however, that a default of Ameren Missouri or Ameren Illinois under the applicable 2012 Credit Agreement will also be deemed to constitute a default of Ameren under such agreement. Defaults include a cross-default to a default of 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 $50 million in the
aggregate (including under the other 2012 Credit Agreement). However, under the default provisions of the 2012 Credit Agreements, any default of Ameren under any such 2012 Credit Agreements that results solely from a default of Ameren Missouri or Ameren Illinois thereunder does not result in a cross-default of Ameren under the other 2012 Credit Agreement. Further, the 2012 Credit Agreement default provisions provide that an Ameren default under any of the 2012 Credit Agreements does not trigger a default by Ameren Missouri or Ameren Illinois. Finally, for the purpose of determining whether any event relating solely to Genco or its subsidiaries constitutes a default with respect to Ameren under either 2012 Credit Agreement, Ameren will have the option to exclude Genco and its subsidiaries from the subsidiaries of Ameren that are subject to such 2012 Credit Agreement, provided that certain conditions are satisfied. These conditions include (1) the reduction of Ameren's Borrowing Sublimits under each 2012 Credit Agreement by not less than $150 million (as determined based on the highest Borrower Sublimit that has been in effect for Ameren at any time under the applicable 2012 Credit Agreement) and (2) that such default would not have a material adverse effect on Ameren (as such term is defined in the 2012 Credit Agreements).
None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit agreements at December 31, 20122013.
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
Ameren Missouri, Ameren Illinois, and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren and AERG may participate in the utility money pool only as lenders.a lender. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2012 Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but it is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants
receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 20122013, was 0.13%. There were no utility money pool borrowings during the year ended December 31, 2011.
Non-state-regulated Subsidiaries
Ameren, Ameren Services, AER, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the 2012 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2012, was 0.61%0.14% (20112012 - 0.77%0.13%).
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, 20122013, 20112012, and 20102011.
Unilateral Borrowing Agreement
In addition, a unilateral borrowing agreement exists among Ameren, Ameren Illinois, and Ameren Services, which enables Ameren Illinois to make short-term borrowings directly from
Ameren. The aggregate amount of borrowings outstanding at any time by Ameren Illinois under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding Ameren Illinois external credit facility borrowings, or commercial paper issuances, may not exceed $500 million, pursuant to authorization from the ICC. Ameren Illinois is not currently borrowing under the unilateral borrowing agreement. Ameren Services is responsible for the operation and administration of the unilateral borrowing agreement.
NOTE 5 -– LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents long-term debt outstanding, including maturities due within one year, for the Ameren Companies and Genco as of December 31, 20122013, and 20112012:
| | | | 2012 | | 2011 | 2013 | | 2012 |
| Ameren (Parent): | | | | | | |
| 8.875% Senior unsecured notes due 2014 | $ | 425 |
| | $ | 425 |
| $ | 425 |
| | $ | 425 |
|
| Less: Unamortized discount and premium | (1 | ) | | (1 | ) | — |
| | (1 | ) |
| Less: Maturities due within one year | | (425 | ) | | — |
|
| Long-term debt, net | $ | 424 |
| | $ | 424 |
| $ | — |
| | $ | 424 |
|
| Ameren Missouri: | | | | | | |
Senior secured notes:(a) | | | | | | |
| 5.25% Senior secured notes due 2012 | $ | — |
| | $ | 173 |
| |
| 4.65% Senior secured notes due 2013 | 200 |
| | 200 |
| — |
| | 200 |
|
| 5.50% Senior secured notes due 2014 | 104 |
| | 104 |
| 104 |
| | 104 |
|
| 4.75% Senior secured notes due 2015 | 114 |
| | 114 |
| 114 |
| | 114 |
|
| 5.40% Senior secured notes due 2016 | 260 |
| | 260 |
| 260 |
| | 260 |
|
| 6.40% Senior secured notes due 2017 | 425 |
| | 425 |
| 425 |
| | 425 |
|
6.00% Senior secured notes due 2018(b) | 179 |
| | 250 |
| 179 |
| | 179 |
|
| 5.10% Senior secured notes due 2018 | 199 |
| | 200 |
| 199 |
| | 199 |
|
6.70% Senior secured notes due 2019(b) | 329 |
| | 450 |
| 329 |
| | 329 |
|
| 5.10% Senior secured notes due 2019 | 244 |
| | 300 |
| 244 |
| | 244 |
|
| 5.00% Senior secured notes due 2020 | 85 |
| | 85 |
| 85 |
| | 85 |
|
| 5.50% Senior secured notes due 2034 | 184 |
| | 184 |
| 184 |
| | 184 |
|
| 5.30% Senior secured notes due 2037 | 300 |
| | 300 |
| 300 |
| | 300 |
|
8.45% Senior secured notes due 2039(b) | 350 |
| | 350 |
| 350 |
| | 350 |
|
3.90% Senior secured notes due 2042(b) | 485 |
| | — |
| 485 |
| | 485 |
|
| Environmental improvement and pollution control revenue bonds: | | | | | | |
1992 Series due 2022(c)(d) | 47 |
| | 47 |
| 47 |
| | 47 |
|
1993 5.45% Series due 2028(e) | 44 |
| | 44 |
| (e) |
| | 44 |
|
1998 Series A due 2033(c)(d) | 60 |
| | 60 |
| 60 |
| | 60 |
|
1998 Series B due 2033(c)(d) | 50 |
| | 50 |
| 50 |
| | 50 |
|
1998 Series C due 2033(c)(d) | 50 |
| | 50 |
| 50 |
| | 50 |
|
| Capital lease obligations: | | | | | | |
| City of Bowling Green capital lease (Peno Creek CT) through 2022 | 64 |
| | 69 |
| 59 |
| | 64 |
|
| Audrain County capital lease (Audrain County CT) due 2023 | 240 |
| | 240 |
| 240 |
| | 240 |
|
| Total long-term debt, gross | 4,013 |
| | 3,955 |
| 3,764 |
| | 4,013 |
|
| Less: Unamortized discount and premium | (7 | ) | | (5 | ) | (7 | ) | | (7 | ) |
| Less: Maturities due within one year | (205 | ) | | (178 | ) | (109 | ) | | (205 | ) |
| Long-term debt, net | $ | 3,801 |
| | $ | 3,772 |
| $ | 3,648 |
| | $ | 3,801 |
|
| | | | 2012 | | 2011 | 2013 | | 2012 |
| Ameren Illinois: | | | | | | |
| Senior secured notes: | | | | | | |
8.875% Senior secured notes due 2013(h)(f) | $ | 150 |
| | $ | 150 |
| $ | — |
| | $ | 150 |
|
6.20% Senior secured notes due 2016(f) | 54 |
| | 54 |
| 54 |
| | 54 |
|
6.25% Senior secured notes due 2016(g) | 75 |
| | 75 |
| 75 |
| | 75 |
|
6.125% Senior secured notes due 2017(i)(h) | 250 |
| | 250 |
| 250 |
| | 250 |
|
6.25% Senior secured notes due 2018(i)(h) | 144 |
| | 337 |
| 144 |
| | 144 |
|
9.75% Senior secured notes due 2018(i)(h) | 313 |
| | 400 |
| 313 |
| | 313 |
|
2.70% Senior secured notes due 2022(i)(h) | 400 |
| | — |
| 400 |
| | 400 |
|
6.125% Senior secured notes due 2028(g) | 60 |
| | 60 |
| 60 |
| | 60 |
|
6.70% Senior secured notes due 2036(g) | 61 |
| | 61 |
| 61 |
| | 61 |
|
6.70% Senior secured notes due 2036(f) | 42 |
| | 42 |
| 42 |
| | 42 |
|
4.80% Senior secured notes due 2043(g) | | 280 |
| | — |
|
| Environmental improvement and pollution control revenue bonds: | | | | | | |
| 6.20% Series 1992B due 2012 | — |
| | 1 |
| |
| 2000 Series A 5.50% due 2014 | — |
| | 51 |
| |
5.90% Series 1993 due 2023(j) | 32 |
| | 32 |
| |
5.70% 1994A Series due 2024(k) | 36 |
| | 36 |
| |
1993 Series C-1 5.95% due 2026(l) | 35 |
| | 35 |
| |
1993 Series C-2 5.70% due 2026(l) | 8 |
| | 8 |
| |
1993 Series B-1 due 2028(d)(l) | 17 |
| | 17 |
| |
5.40% 1998A Series due 2028(k) | 19 |
| | 19 |
| |
5.40% 1998B Series due 2028(k) | 33 |
| | 33 |
| |
5.90% Series 1993 due 2023(i) | | 32 |
| | 32 |
|
5.70% 1994A Series due 2024(j) | | 36 |
| | 36 |
|
1993 Series C-1 5.95% due 2026(k) | | 35 |
| | 35 |
|
1993 Series C-2 5.70% due 2026(k) | | 8 |
| | 8 |
|
1993 Series B-1 due 2028(d)(k) | | 17 |
| | 17 |
|
5.40% 1998A Series due 2028(j) | | 19 |
| | 19 |
|
5.40% 1998B Series due 2028(j) | | 33 |
| | 33 |
|
| Fair-market value adjustments | 4 |
| | 5 |
| 4 |
| | 4 |
|
| Total long-term debt, gross | 1,733 |
| | 1,666 |
| 1,863 |
| | 1,733 |
|
| Less: Unamortized discount and premium | (6 | ) | | (8 | ) | (7 | ) | | (6 | ) |
| Less: Maturities due within one year | (150 | ) | | (1 | ) | — |
| | (150 | ) |
| Long-term debt, net | $ | 1,577 |
| | $ | 1,657 |
| $ | 1,856 |
| | $ | 1,577 |
|
| Genco: | | | | |
| Unsecured notes: | | | | |
| Senior notes Series F 7.95% due 2032 | $ | 275 |
| | $ | 275 |
| |
| Senior notes Series H 7.00% due 2018 | 300 |
| | 300 |
| |
| Senior notes Series I 6.30% due 2020 | 250 |
| | 250 |
| |
| Total long-term debt, gross | 825 |
| | 825 |
| |
| Less: Unamortized discount and premium | (1 | ) | | (1 | ) | |
| Less: Maturities due within one year | — |
| | — |
| |
| Long-term debt, net | $ | 824 |
| | $ | 824 |
| |
| Ameren consolidated long-term debt, net | $ | 6,626 |
| | $ | 6,677 |
| $ | 5,504 |
| | $ | 5,802 |
|
| |
| (a) | These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based onConsidering the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042. |
| |
| (b) | Ameren Missouri has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its first mortgage bonds. Ameren Missouri has also agreed to prevent a first mortgage bond release date from occurring as long as any of the 8.45% senior secured notes due 2039 and any of the 3.90% senior secured notes due 2042 remain outstanding. |
| |
| (c) | These bonds are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri's senior secured notes. The bonds are also backed by an insurance guarantee policy. |
| |
| (d) | Interest rates, and periods during which such rates apply, vary depending on our selection of defined rate modes. Maximum interest rates could range up to 18% depending on the series of bonds. The average interest rates for 20122013 and 20112012 were as follows: |
| | | | 2012 | | 2011 | 2013 | | 2012 |
| Ameren Missouri 1992 Series | 0.30 | % | | 0.34 | % | 0.17% | | 0.30% |
| Ameren Missouri 1998 Series A | 0.65 | % | | 0.69 | % | 0.34% | | 0.65% |
| Ameren Missouri 1998 Series B | 0.64 | % | | 0.68 | % | 0.33% | | 0.64% |
| Ameren Missouri 1998 Series C | 0.64 | % | | 0.69 | % | 0.34% | | 0.64% |
| Ameren Illinois 1993 Series B-1 | 0.22 | % | | 0.28 | % | 0.14% | | 0.22% |
| |
| (e) | These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and are secured by substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value. Less than $1 million principal amount of the bonds remain outstanding. |
| |
| (f) | These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Considering the CILCO first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2023. |
and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the CILCO first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2023.
| |
| (g) | These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based onConsidering the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028. |
| |
| (h) | Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase, or otherwise retire in full its CILCO first mortgage bonds, and therefore a CILCO first mortgage bond release date will not occur while any of such notes are outstanding. |
| |
(i) | Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its Ameren Illinois mortgage bonds, andbonds; therefore, an Ameren Illinois first mortgage bond release date will not occur as long as any of these notes are outstanding. |
| |
(j)(i) | These bonds are first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture and are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value. |
| |
(k)(j) | These bonds are mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture and are secured by substantially all property of the former IP and CIPS. The bonds are callable at 100% of par value. The bonds are also backed by an insurance guarantee policy. |
| |
(l)(k) | The bonds are callable at 100% of par value. |
The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies and Genco at December 31, 20122013:
| | | | Ameren (Parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a)(b) | | Genco(a) | | Ameren Consolidated | Ameren (Parent)(a) | | Ameren Missouri(a) | | Ameren Illinois(a)(b) | | Ameren Consolidated |
| 2013 | $ | — |
| | $ | 205 |
| | $ | 150 |
| | $ | — |
| | $ | 355 |
| |
| 2014 | 425 |
| | 109 |
| | — |
| | — |
| | 534 |
| $ | 425 |
| | $ | 109 |
| | $ | — |
| | $ | 534 |
|
| 2015 | — |
| | 120 |
| | — |
| | — |
| | 120 |
| — |
| | 120 |
| | — |
| | 120 |
|
| 2016 | — |
| | 266 |
| | 129 |
| | — |
| | 395 |
| — |
| | 266 |
| | 129 |
| | 395 |
|
| 2017 | — |
| | 431 |
| | 250 |
| | — |
| | 681 |
| — |
| | 431 |
| | 250 |
| | 681 |
|
| 2018 | | — |
| | 383 |
| | 457 |
| | 840 |
|
| Thereafter | — |
| | 2,882 |
| | 1,200 |
| | 825 |
| | 4,907 |
| — |
| | 2,455 |
| | 1,023 |
| | 3,478 |
|
| Total | $ | 425 |
| | $ | 4,013 |
| | $ | 1,729 |
| | $ | 825 |
| | $ | 6,992 |
| $ | 425 |
| | $ | 3,764 |
| | $ | 1,859 |
| | $ | 6,048 |
|
| |
| (a) | Excludes unamortized discount and premium of $17 million, and $7 million, $6 million and $1 million at Ameren (Parent),Missouri and Ameren Missouri, Ameren Illinois, and Genco, respectively. |
| |
| (b) | Excludes $4 million related to Ameren Illinois’ long-term debt fair-market value adjustments, which are being amortized to interest expense over the remaining life of the debt. |
All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends and have voting rights. Preferred stock not subject to mandatory redemption of Ameren's subsidiaries was included in "Noncontrolling Interests" on Ameren's consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois that is not subject to mandatory redemption. The preferred stock is redeemable, at the option of the issuer, at the prices shown below as of December 31, 20122013, and 20112012:
| | | | | Redemption Price(per share) | | 2012 | | 2011 | | Redemption Price(per share) | | 2013 | | 2012 |
| Ameren Missouri: | | | | | | | | | | | | |
| Without par value and stated value of $100 per share, 25 million shares authorized | Without par value and stated value of $100 per share, 25 million shares authorized | | | | | | | Without par value and stated value of $100 per share, 25 million shares authorized | | | | | | |
| $3.50 Series | 130,000 shares | | $ | 110.00 |
| | $ | 13 |
| | $ | 13 |
| 130,000 shares | | $ | 110.00 |
| | $ | 13 |
| | $ | 13 |
|
| $3.70 Series | 40,000 shares | | 104.75 |
| | 4 |
| | 4 |
| 40,000 shares | | 104.75 |
| | 4 |
| | 4 |
|
| $4.00 Series | 150,000 shares | | 105.625 |
| | 15 |
| | 15 |
| 150,000 shares | | 105.625 |
| | 15 |
| | 15 |
|
| $4.30 Series | 40,000 shares | | 105.00 |
| | 4 |
| | 4 |
| 40,000 shares | | 105.00 |
| | 4 |
| | 4 |
|
| $4.50 Series | 213,595 shares | | 110.00 |
| (a) | 21 |
| | 21 |
| 213,595 shares | | 110.00 |
| (a) | 21 |
| | 21 |
|
| $4.56 Series | 200,000 shares | | 102.47 |
| | 20 |
| | 20 |
| 200,000 shares | | 102.47 |
| | 20 |
| | 20 |
|
| $4.75 Series | 20,000 shares | | 102.176 |
| | 2 |
| | 2 |
| 20,000 shares | | 102.176 |
| | 2 |
| | 2 |
|
| $5.50 Series A | 14,000 shares | | 110.00 |
| | 1 |
| | 1 |
| 14,000 shares | | 110.00 |
| | 1 |
| | 1 |
|
| Total | Total | | | | $ | 80 |
| | $ | 80 |
| Total | | | | $ | 80 |
| | $ | 80 |
|
| Ameren Illinois: | | | | | | | | | | | | |
| With par value of $100 per share, 2 million shares authorized | With par value of $100 per share, 2 million shares authorized | | | | | | | With par value of $100 per share, 2 million shares authorized | | | | | | |
| 4.00% Series | 144,275 shares | | $ | 101.00 |
| | $ | 14 |
| | $ | 14 |
| 144,275 shares | | $ | 101.00 |
| | $ | 14 |
| | $ | 14 |
|
| 4.08% Series | 45,224 shares | | 103.00 |
| | 5 |
| | 5 |
| 45,224 shares | | 103.00 |
| | 5 |
| | 5 |
|
| 4.20% Series | 23,655 shares | | 104.00 |
| | 2 |
| | 2 |
| 23,655 shares | | 104.00 |
| | 2 |
| | 2 |
|
| 4.25% Series | 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
| 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
|
| 4.26% Series | 16,621 shares | | 103.00 |
| | 2 |
| | 2 |
| 16,621 shares | | 103.00 |
| | 2 |
| | 2 |
|
| 4.42% Series | 16,190 shares | | 103.00 |
| | 2 |
| | 2 |
| 16,190 shares | | 103.00 |
| | 2 |
| | 2 |
|
| 4.70% Series | 18,429 shares | | 103.00 |
| | 2 |
| | 2 |
| 18,429 shares | | 103.00 |
| | 2 |
| | 2 |
|
| 4.90% Series | 73,825 shares | | 102.00 |
| | 7 |
| | 7 |
| 73,825 shares | | 102.00 |
| | 7 |
| | 7 |
|
| 4.92% Series | 49,289 shares | | 103.50 |
| | 5 |
| | 5 |
| 49,289 shares | | 103.50 |
| | 5 |
| | 5 |
|
| 5.16% Series | 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
| 50,000 shares | | 102.00 |
| | 5 |
| | 5 |
|
| 6.625% Series | 124,273.75 shares | | 100.00 |
| | 12 |
| | 12 |
| 124,274 shares | | 100.00 |
| | 12 |
| | 12 |
|
| 7.75% Series | 4,542 shares | | 100.00 |
| | 1 |
| | 1 |
| 4,542 shares | | 100.00 |
| | 1 |
| | 1 |
|
| Total | Total | | | | $ | 62 |
| | $ | 62 |
| Total | | | | $ | 62 |
| | $ | 62 |
|
Total Ameren(b) | Total Ameren(b) | | | | $ | 142 |
| | $ | 142 |
| Total Ameren(b) | | | | $ | 142 |
| | $ | 142 |
|
| |
| (a) | In the event of voluntary liquidation, $105.50. |
| |
(b) | Preferred stock not subject to mandatory redemption of Ameren's subsidiaries was included in "Noncontrolling Interests" on Ameren's consolidated balance sheet. |
Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding. Ameren Missouri has 7.5 million shares of $1 par value preference stock authorized, with no such preference stock outstanding. Ameren Illinois has 2.6 million shares of no par value preferred stock authorized, with no shares outstanding.
Ameren
Ameren filed a Form S-8 registration statement with the SEC in October 2013, authorizing the offering of 4 million additional shares of its common stock under its 401(k) plan. Shares of common stock sold under the 401(k) plan are, at Ameren’s option, newly issued shares, treasury shares, or shares
purchased in the open market or in privately negotiated transactions.
Ameren filed a Form S-3 registration statement with the
SEC in June 2011, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. In 2013 and 2012, Ameren shares were purchased in the open market for DRPlus and its 401(k) plan. Under DRPlus and its 401(k) plan, Ameren issued 2.2 million and 3.0 millionshares of common stock in 2011, and 2010, respectively, which were valued at $65 million and $80 million for the respective years..
Ameren Missouri
In October 2013, $44 million of Ameren Missouri’s 1993 5.45% Series tax-exempt first mortgage bonds were redeemed at par value plus accrued interest, and $200 million of Ameren Missouri’s 4.65% senior secured notes matured and were retired.
On September 11, 2012, Ameren Missouri issued $485 million principal amount of 3.90% senior secured notes due September 15, 2042, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2013. These notes are secured by first mortgage bonds. Ameren Missouri received net proceeds of $478 million. The proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Missouri's tender offer on September 20, 2012, including the payment of interest and all related fees and expenses, and to retire the $173 million principal amount 5.25% senior secured notes that matured in September 2012.
On September 20, 2012, Ameren Missouri completed its tender offer to purchase for cash its outstanding 6.00% senior secured notes due 2018, 6.70% senior secured notes due 2019, 5.10% senior secured notes due 2018, and 5.10% senior secured notes due 2019. Any notes that were not tendered and purchased in the tender offer remain outstanding and continue to be obligations of Ameren Missouri. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items ofrelated to the tender offer:
|
| | | | | | | | | | | |
| Senior Secured Notes | Principal Amount Repurchased | | Premium Plus Accrued and Unpaid Interest(a) | | Principal Amount Outstanding After Tender Offer |
| 6.00% senior secured notes due 2018 | $ | 71 |
| | $ | 19 |
| | $ | 179 |
|
| 6.70% senior secured notes due 2019 | 121 |
| | 35 |
| | 329 |
|
| 5.10% senior secured notes due 2018 | 1 |
| | (b) |
| | 199 |
|
| 5.10% senior secured notes due 2019 | 56 |
| | 12 |
| | 244 |
|
| |
| (a) | The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $485 million 3.90% senior secured notes due 2042. |
| |
| (b) | Amount is less than $1 million. |
Ameren Illinois
In January 2014, Ameren Illinois redeemed the following environmental improvement and pollution control revenue bonds at par value plus accrued interest: |
| | | |
| Senior Secured Notes | Principal Amount |
5.90% Series 1993 due 2023(a) | $ | 32 |
|
5.70% 1994A Series due 2024(a) | 36 |
|
| 1993 Series C-1 5.95% due 2026 | 35 |
|
| 1993 Series C-2 5.70% due 2026 | 8 |
|
| 5.40% 1998A Series due 2028 | 19 |
|
| 5.40% 1998B Series due 2028 | 33 |
|
| Total amount redeemed | $ | 163 |
|
| |
| (a) | Less than $1 million principal amount of the bonds remain outstanding as of January 31, 2014. |
In December 2013, Ameren Illinois issued $280 million principal amount of 4.80% senior secured notes due December 15, 2043, with interest payable semiannually on June 15 and December 15 of each year, beginning June 15, 2014. These notes are secured by first mortgage bonds. Ameren Illinois received net proceeds of $276 million. The proceeds were used, together with other available cash, to repay
at maturity $150 million aggregate principal amount of its 8.875% senior secured notes due December 15, 2013, and to repay its short-term debt.
On August 20, 2012, Ameren Illinois issued $400 million principal amount of 2.70% senior secured notes due September 1, 2022, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2013. These notes are secured by first mortgage bonds. Ameren Illinois received net proceeds of $397 million. The proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Illinois' tender offer on August 27, 2012, including the payment of interest and all related fees and expenses, and to redeem all $51 million principal amount of 5.50% pollution control revenue bonds at par value plus accrued interest.
On August 27, 2012, Ameren Illinois completed its tender offer to purchase for cash its outstanding 9.75% senior secured notes due 2018 and 6.25% senior secured notes due 2018. Any notes that were not tendered and purchased in the tender offer remain outstanding and continue to be obligations of Ameren Illinois. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items ofrelated to the tender offer: |
| | | | | | | | | | | |
| Senior Secured Notes | Principal Amount Repurchased | | Premium Plus Accrued and Unpaid Interest(a) | | Principal Amount Outstanding After Tender Offer |
| 9.75% senior secured notes due 2018 | $ | 87 |
| | $ | 36 |
| | $ | 313 |
|
| 6.25% senior secured notes due 2018 | 194 |
| | 47 |
| | 144 |
|
| |
| (a) | The premiumsPremiums paid in the amount of $21 million in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $400 million 2.70% senior secured notes due 2022. Premiums of $15 million were expensed in 2013 as a result of disallowances in the ICC's December 2013 electric and natural gas rate orders. See Note 2 – Rate and Regulatory Matters for further information regarding the disallowances.
|
In November 2012, $1$1 million principal amount of Ameren Illinois' 6.20% Series 1992B Pollution Control revenue bonds matured and were retired.
Indenture Provisions and Other Covenants
Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable as of December 31, 20122013, at an assumed interest rate of 6% and dividend rate of 7%.
| | | | Required Interest Coverage Ratio(a) | Actual Interest Coverage Ratio | Bonds Issuable(b) | | Required Dividend Coverage Ratio(c) | Actual Dividend Coverage Ratio | Preferred Stock Issuable | Required Interest Coverage Ratio(a) | Actual Interest Coverage Ratio | Bonds Issuable(b) | | Required Dividend Coverage Ratio(c) | Actual Dividend Coverage Ratio | Preferred Stock Issuable |
| Ameren Missouri | >2.0 | 4.6 |
| $ | 4,056 |
| | >2.5 | 122.8 |
| $ | 2,351 |
| >2.0 | 4.5 |
| $ | 3,831 |
| | >2.5 | 116.5 |
| $ | 2,228 |
|
| Ameren Illinois | >2.0 | 7.1 |
| 3,439 |
| (d) | >1.5 | 2.8 |
| 203 |
| >2.0 | 6.8 |
| 3,565 |
| (d) | >1.5 | 2.4 |
| 203 |
|
| |
| (a) | Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. |
| |
| (b) | Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $485729 million and $645365 million at Ameren Missouri and Ameren Illinois, respectively. |
| |
| (c) | Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. |
| |
| (d) | Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture. |
Ameren’s indenture 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 2012 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.
Ameren Missouri and Ameren Illinois and 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, 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, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.
Ameren Illinois’ articles of incorporation require dividend
payments on its 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. Ameren Illinois committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization after the Ameren Illinois Merger and AERG distribution.capitalization. As of December 31, 20122013, Ameren Illinois’ ratio of common stock equity to total capitalization was 57%55%.
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 principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the 12 months ended and as of December 31, 2012:
|
| | | |
| Required Ratio | Actual Ratio |
Restricted payment interest coverage ratio(a)
| ≥1.75 | 2.6 |
|
Additional indebtedness interest coverage ratio(b)
| ≥2.50 | 2.6 |
|
Additional indebtedness debt-to-capital ratio(b)
| ≤60% | 44 | % |
| |
(a) | As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test. |
| |
(b) | Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests. |
Genco’s debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.
Under the provisions of Genco's indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than a specified minimum or its leverage ratio is greater than a specified maximum. Based on projections as of December 31, 2012, of its operating results and cash flows, Genco expects that, by the end of the first quarter of 2013, its interest coverage ratio will be less than the minimum ratio required for the company to borrow additional funds from external, third-party sources. Genco's indenture does not restrict intercompany borrowings from Ameren's non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren's control. If a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. Ameren has sought to have its Merchant Generation business segment and Genco fund their operations internally and not rely on financing from Ameren. In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. As a result, Ameren no longer considers the Merchant Generation segment to be a core component of its future business strategy. See Note 17 - Impairment and Other Charges for additional Merchant Generation information.
In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable requirements in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2012,2013, 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. See Note 14 - Related Party16 – Divestiture Transactions and Discontinued Operations for Ameren (parent) guarantees and letters of credit issued to support New AER based on behalf of its subsidiaries.
the transaction agreement with IPH.
NOTE 6 -– OTHER INCOME AND EXPENSES
The following table presents the components of "Other Income and Expenses" in the Ameren Companies’ statements of income (loss) for the years ended December 31, 20122013, 20112012, and 20102011:
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 | |
Ameren:(a) | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | |
| Allowance for equity funds used during construction | | $ | 37 |
| | $ | 36 |
| | $ | 34 |
| |
| Interest income on industrial development revenue bonds | | 27 |
| | 28 |
| | 28 |
| |
| Interest and dividend income | $ | 5 |
| (b) | $ | 4 |
| | $ | 5 |
| 3 |
| | 4 |
| (b) | 3 |
| |
| Interest income on industrial development revenue bonds | 28 |
| | 28 |
| | 28 |
| |
| Allowance for equity funds used during construction | 36 |
| | 34 |
| | 52 |
| |
| Other | 2 |
| | 3 |
| | 5 |
| 2 |
| | 2 |
| | 3 |
| |
| Total miscellaneous income | $ | 71 |
| | $ | 69 |
| | $ | 90 |
| $ | 69 |
| | $ | 70 |
| | $ | 68 |
| |
| Miscellaneous expense: | | | | | | | | | | | |
| Donations | $ | 24 |
| (c) | $ | 8 |
| | $ | 19 |
| $ | 12 |
| | $ | 24 |
| (c) | $ | 8 |
| |
| Other | 13 |
| | 15 |
| | 14 |
| 14 |
| | 13 |
| | 15 |
| |
| Total miscellaneous expense | $ | 37 |
| | $ | 23 |
| | $ | 33 |
| $ | 26 |
| | $ | 37 |
| | $ | 23 |
| |
| Ameren Missouri: | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | |
| Allowance for equity funds used during construction | | $ | 31 |
| | $ | 31 |
| | $ | 30 |
| |
| Interest income on industrial development revenue bonds | | 27 |
| | 28 |
| | 28 |
| |
| Interest and dividend income | $ | 4 |
| (b) | $ | 2 |
| | $ | 3 |
| — |
| | 4 |
| (b) | 2 |
| |
| Interest income on industrial development revenue bonds | 28 |
| | 28 |
| | 28 |
| |
| Allowance for equity funds used during construction | 31 |
| | 30 |
| | 50 |
| |
| Other | — |
| | 1 |
| | 2 |
| — |
| | — |
| | 1 |
| |
| Total miscellaneous income | $ | 63 |
| | $ | 61 |
| | $ | 83 |
| $ | 58 |
| | $ | 63 |
| | $ | 61 |
| |
| Miscellaneous expense: | | | | | | | | | | | |
| Donations | $ | 9 |
| | $ | 3 |
| | $ | 8 |
| $ | 4 |
| | $ | 9 |
| | $ | 3 |
| |
| Other | 5 |
| | 7 |
| | 5 |
| 7 |
| | 5 |
| | 7 |
| |
| Total miscellaneous expense | $ | 14 |
| | $ | 10 |
| | $ | 13 |
| $ | 11 |
| | $ | 14 |
| | $ | 10 |
| |
| Ameren Illinois: | | | | | | | | | | | |
| Miscellaneous income: | | | | | | | | | | | |
| Allowance for equity funds used during construction | | $ | 6 |
| | $ | 5 |
| | $ | 4 |
| |
| Interest and dividend income | $ | — |
| | $ | 1 |
| | $ | 1 |
| 2 |
| | — |
| | 1 |
| |
| Allowance for equity funds used during construction | 5 |
| | 4 |
| | 2 |
| |
| Other | 2 |
| | 2 |
| | 4 |
| 2 |
| | 2 |
| | 2 |
| |
| Total miscellaneous income | $ | 7 |
| | $ | 7 |
| | $ | 7 |
| $ | 10 |
| | $ | 7 |
| | $ | 7 |
| |
| Miscellaneous expense: | | | | | | | | | | | |
| Donations | $ | 11 |
| (c) | $ | 1 |
| | $ | 5 |
| $ | 4 |
| | $ | 11 |
| (c) | $ | 1 |
| |
| Other | 6 |
| | 5 |
| | 8 |
| 5 |
| | 6 |
| | 5 |
| |
| Total miscellaneous expense | $ | 17 |
| | $ | 6 |
| | $ | 13 |
| $ | 9 |
| | $ | 17 |
| | $ | 6 |
| |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | Includes interest income received in 2012 relating to a 2012 refund of charges included in an expired power purchase agreement with Entergy. See Note 2 -– Rate and Regulatory Matters for additional information. |
| |
| (c) | Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' 2012 participation in the electric delivery formula ratemaking process. |
NOTE 7 -– DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity,power, and uranium. Such price fluctuations may cause the following:
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;
market values of coal, natural gas and uranium inventories that differ from the cost of those commodities in inventory; and
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.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of December 31, 20122013, and 20112012:. As of December 31, 2013, these contracts ran through October 2016, October 2019, May 2032, and October 2016 for fuel oils, natural gas, power, and uranium, respectively.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Quantity (in millions, except as indicated) |
| Commodity | Accrual & NPNS Contracts(a) | | Cash Flow Hedges(b) | | Other Derivatives(c) | | Derivatives That Qualify for Regulatory Deferral(d) |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 | | 2011 | | 2012 | | 2011 |
| Coal (in tons) | | | | | | | | | | | | | | | |
| Ameren Missouri | 96 |
| | 116 |
| | (e) |
| | (e) |
| | — |
| | (e) |
| | (e) |
| | (e) |
|
Other(f) | 39 |
| | 31 |
| | (e) |
| | (e) |
| | 7 |
| | (e) |
| | (e) |
| | (e) |
|
| Ameren | 135 |
| | 147 |
| | (e) |
| | (e) |
| | 7 |
| | (e) |
| | (e) |
| | (e) |
|
Fuel oils (in gallons)(g) | | | | | | | | | | | | | | | |
| Ameren Missouri | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | 26 |
| | 53 |
|
Other(f) | (e) |
| | (e) |
| | (e) |
| | (e) |
| | 52 |
| | 36 |
| | (e) |
| | (e) |
|
| Ameren | (e) |
| | (e) |
| | (e) |
| | (e) |
| | 52 |
| | 36 |
| | 26 |
| | 53 |
|
| Natural gas (in mmbtu) | | | | | | | | | | | | | | | |
| Ameren Missouri | 4 |
| | 8 |
| | (e) |
| | (e) |
| | — |
| | 9 |
| | 19 |
| | 19 |
|
| Ameren Illinois | 16 |
| | 42 |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | 128 |
| | 174 |
|
Other(f) | (e) |
| | (e) |
| | (e) |
| | (e) |
| | 47 |
| | 8 |
| | (e) |
| | (e) |
|
| Ameren | 20 |
| | 50 |
| | (e) |
| | (e) |
| | 47 |
| | 17 |
| | 147 |
| | 193 |
|
| Power (in megawatthours) | | | | | | | | | | | | | | | |
| Ameren Missouri | 3 |
| | 1 |
| | (e) |
| | (e) |
| | 2 |
| | 1 |
| | 9 |
| | 6 |
|
| Ameren Illinois | 21 |
| | 11 |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | 14 |
| | 24 |
|
Other(f) | 66 |
| | 61 |
| | 9 |
| | 17 |
| | 34 |
| | 30 |
| | — |
| | (9 | ) |
| Ameren | 90 |
| | 73 |
| | 9 |
| | 17 |
| | 36 |
| | 31 |
| | 23 |
| | 21 |
|
Renewable energy credits(h) | | | | | | | | | | | | | | | |
| Ameren Missouri | 3 |
| | 4 |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
|
| Ameren Illinois | 12 |
| | 12 |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
|
Other(f) | 1 |
| | 1 |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
|
| Ameren | 16 |
| | 17 |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
|
| Uranium (pounds in thousands) | | | | | | | | | | | | | | | |
| Ameren Missouri & Ameren | 5,142 |
| | 5,553 |
| | (e) |
| | (e) |
| | (e) |
| | (e) |
| | 446 |
| | 148 |
|
|
| | | | | | |
| | Quantity (in millions, except as indicated) |
| | 2013 | 2012 |
| Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren |
Fuel oils (in gallons)(a) | 66 | (b) | 66 | 70 | (b) | 70 |
| Natural gas (in mmbtu) | 28 | 108 | 136 | 19 | 128 | 147 |
| Power (in megawatthours) | 3 | 11 | 14 | 11 | 14 | 25 |
| Uranium (pounds in thousands) | 796 | (b) | 796 | 446 | (b) | 446 |
| |
| (a) | Accrual contracts include commodity contracts that do not qualify as derivatives. As of December 31, 2012, these contracts ran through December 2017, March 2015, September 2035, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively. |
| |
(b) | As of December 31, 2012, these contracts ran through December 2016 for power. |
| |
(c) | As of December 31, 2012, these contracts ran through December 2015, October 2016, April 2015, and December 2016 for coal, fuel oils, natural gas, and power, respectively. |
| |
(d) | As of December 31, 2012, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively. |
| |
(f) | Includes AERG and Genco contracts for coal and fuel oils, Marketing Company and Genco contracts for natural gas, Marketing Company contracts for power and renewable energy credits, and intercompany eliminations for power. |
| |
(g) | Fuel oils consist of heating oil, ultra-low-sulfur diesel, and crude oil. |
| |
(h)(b) | A renewable energy credit is created for every megawatthour of renewable energy generated. Ameren contracts include renewable energy credits from solar, wind, and landfill gas-generated power.Not applicable. |
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 purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on 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. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting 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 and comprehensive 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 or the statement of income and comprehensive 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. Ameren Missouri and Ameren Illinois believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.
Certain derivative As of December 31, 2013, and 2012, all contracts are entered into on a regular basis as part of our risk management program but do notthat qualify for or we do not choose to elect, the NPNS exception, hedge
accounting orreceive regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income or the statement of income and comprehensive income in the period in which the change occurs.deferral.
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 commodity contracts.
The following table presents the carrying value and balance sheet location of all derivative instruments as of December 31, 20122013, and 20112012:
|
| | | | | | | | | | | |
| | Balance Sheet Location | | Ameren(a) | | Ameren Missouri | | Ameren Illinois | |
| 2012 | | | | | | | | |
| Derivative assets designated as hedging instruments | | | | | | | |
| Commodity contracts: | | | | | | | |
| Power | MTM derivative assets | $ | 25 |
| $ | (b) |
| $ | (b) |
| |
| | Other assets | | 14 |
| | — |
| | — |
| |
| | Total assets | $ | 39 |
| $ | — |
| $ | — |
| |
Derivative assets not designated as hedging instruments(c) | | | | | | | |
| Commodity contracts: | | | | | | | |
| Coal | Other assets | $ | 1 |
| $ | — |
| $ | — |
| |
| Fuel oils | MTM derivative assets | | 10 |
| | (b) |
| | (b) |
| |
| | Other current assets | | — |
| | 8 |
| | — |
| |
| | Other assets | | 5 |
| | 4 |
| | — |
| |
| Natural gas | MTM derivative assets | | 5 |
| | (b) |
| | (b) |
| |
| | Other current assets | | — |
| | — |
| | 1 |
| |
| | Other assets | | 1 |
| | 1 |
| | — |
| |
| Power | MTM derivative assets | | 85 |
| | (b) |
| | (b) |
| |
| | Other current assets | | — |
| | 14 |
| | — |
| |
| | Other assets | | 16 |
| | 1 |
| | — |
| |
| | Total assets | $ | 123 |
| $ | 28 |
| $ | 1 |
| |
Derivative liabilities not designated as hedging instruments(c) | | | | | | | |
| Commodity contracts: | | | | | | | | |
| Coal | MTM derivative liabilities | $ | 9 |
| $ | (b) |
| $ | — |
| |
| | Other deferred credits and liabilities | | 4 |
| | — |
| | — |
| |
| Fuel oils | MTM derivative liabilities | | 3 |
| | (b) |
| | — |
| |
| | Other current liabilities | | — |
| | 2 |
| | — |
| |
| | Other deferred credits and liabilities | | 3 |
| | 2 |
| | — |
| |
| Natural gas | MTM derivative liabilities | | 68 |
| | (b) |
| | 56 |
| |
| | Other current liabilities | | — |
| | 8 |
| | — |
| |
| | Other deferred credits and liabilities | | 45 |
| | 7 |
| | 38 |
| |
| Power | MTM derivative liabilities | | 74 |
| | (b) |
| | 21 |
| |
| | Other current liabilities | | — |
| | 4 |
| | — |
| |
| | Other deferred credits and liabilities | | 107 |
| | — |
| | 90 |
| |
| Uranium | MTM derivative liabilities | | 1 |
| | (b) |
| | — |
| |
| | Other current liabilities | | — |
| | 1 |
| | — |
| |
| | Other deferred credits and liabilities | | 1 |
| | 1 |
| | — |
| |
| | Total liabilities | $ | 315 |
| $ | 25 |
| $ | 205 |
| |
| | | | Balance Sheet Location | | Ameren(a) | | Ameren Missouri | | Ameren Illinois | | Balance Sheet Location | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2011 | | | | | | | | |
| Derivative assets designated as hedging instruments | | | | | | | | |
| 2013 | | | | | | | |
Derivative assets not designated as hedging instruments(a) | | Derivative assets not designated as hedging instruments(a) | | | | | | |
| Commodity contracts: | | | | | | | | Commodity contracts: | | | | | | |
| Fuel oils | | Other current assets | $ | 6 |
| $ | — |
| $ | 6 |
|
| | | Other assets | | 3 |
| | — |
| | 3 |
|
| Natural gas | | Other current assets | | 1 |
| | 1 |
| | 2 |
|
| Power | MTM derivative assets | $ | 8 |
| $ | (b) |
| $ | (b) |
| | Other current assets | | 23 |
| | — |
| | 23 |
|
| | Other assets | | 16 |
| | — |
| | — |
| | Total assets | $ | 33 |
| $ | 1 |
| $ | 34 |
|
| | Total assets | $ | 24 |
| $ | — |
| $ | — |
| | |
| Derivative liabilities designated as hedging instruments | | | | | | | | |
| Commodity contracts: | | | | | | | | |
| Power | Other deferred credits and liabilities | $ | 1 |
| $ | — |
| $ | — |
| | |
| | Total liabilities | $ | 1 |
| $ | — |
| $ | — |
| | |
Derivative assets not designated as hedging instruments(c) | | | | | | | | |
Derivative liabilities not designated as hedging instruments(a) | | Derivative liabilities not designated as hedging instruments(a) | | | | | | |
| Commodity contracts: | | | | | | | | | | | | | |
| Fuel oils | MTM derivative assets | $ | 29 |
| $ | (b) |
| $ | (b) |
| | MTM derivative liabilities | $ | (b) |
| $ | — |
| $ | 2 |
|
| | Other current assets | | — |
| | 17 |
| | — |
| | Other current liabilities | | 2 |
| | — |
| | — |
|
| | Other assets | | 8 |
| | 6 |
| | — |
| | Other deferred credits and liabilities | | 1 |
| | — |
| | 1 |
|
| Natural gas | MTM derivative assets | | 6 |
| | (b) |
| | (b) |
| | MTM derivative liabilities | | (b) |
| | 27 |
| | 32 |
|
| | Other current assets | | — |
| | 2 |
| | 1 |
| | Other current liabilities | | 5 |
| | — |
| | — |
|
| | Other assets | | — |
| | — |
| | 1 |
| | Other deferred credits and liabilities | | 6 |
| | 19 |
| | 25 |
|
| Power | MTM derivative assets | | 72 |
| | (b) |
| | (b) |
| | MTM derivative liabilities | | (b) |
| | 9 |
| | 13 |
|
| | Other current assets | | — |
| | 30 |
| | — |
| | Other current liabilities | | 4 |
| | — |
| | — |
|
| | Other assets | | 99 |
| | — |
| | 77 |
| | Other deferred credits and liabilities | | — |
| | 99 |
| | 99 |
|
| Uranium | | MTM derivative liabilities | | (b) |
| | — |
| | 5 |
|
| | Total assets | $ | 214 |
| $ | 55 |
| $ | 79 |
| | Other current liabilities | | 5 |
| | — |
| | — |
|
Derivative liabilities not designated as hedging instruments(c) | | | | | | | | |
| | | Other deferred credits and liabilities | | 1 |
| | — |
| | 1 |
|
| | | Total liabilities | $ | 24 |
| $ | 154 |
| $ | 178 |
|
| 2012 | | | | | | | |
Derivative assets not designated as hedging instruments(a) | | Derivative assets not designated as hedging instruments(a) | | | | | | |
| Commodity contracts: | | | | | | | | | | | | | |
| Fuel oils | MTM derivative liabilities | $ | 2 |
| $ | (b) |
| $ | — |
| | Other current assets | $ | 8 |
| $ | — |
| $ | 8 |
|
| | | Other assets | | 4 |
| | — |
| | 4 |
|
| Natural gas | | Other current assets | | — |
| | 1 |
| | 1 |
|
| | | Other assets | | 1 |
| | — |
| | 1 |
|
| Power | | Other current assets | | 14 |
| | — |
| | 14 |
|
| | | Other assets | | 1 |
| | — |
| | 1 |
|
| | | Total assets | $ | 28 |
| $ | 1 |
| $ | 29 |
|
Derivative liabilities not designated as hedging instruments(a) | | Derivative liabilities not designated as hedging instruments(a) | | | | | | |
| Commodity contracts: | | | | | | | |
| Fuel oils | | MTM derivative liabilities | $ | (b) |
| $ | — |
| $ | 2 |
|
| | | Other current liabilities | | 2 |
| | — |
| | — |
|
| | Other current liabilities | | — |
| | 1 |
| | — |
| | Other deferred credits and liabilities | | 2 |
| | — |
| | 2 |
|
| Natural gas | MTM derivative liabilities | | 106 |
| | (b) |
| | 90 |
| | MTM derivative liabilities | | (b) |
| | 56 |
| | 64 |
|
| | Other current liabilities | | — |
| | 13 |
| | — |
| | Other current liabilities | | 8 |
| | — |
| | — |
|
| | Other deferred credits and liabilities | | 92 |
| | 13 |
| | 79 |
| | Other deferred credits and liabilities | | 7 |
| | 38 |
| | 45 |
|
| Power | MTM derivative liabilities | | 53 |
| | (b) |
| | 9 |
| | MTM derivative liabilities | | (b) |
| | 21 |
| | 25 |
|
| | MTM derivative liabilities - affiliates | | (b) |
| | (b) |
| | 200 |
| | Other current liabilities | | 4 |
| | — |
| | — |
|
| | Other current liabilities | | — |
| | 9 |
| | — |
| | Other deferred credits and liabilities | | — |
| | 90 |
| | 90 |
|
| | Other deferred credits and liabilities | | 26 |
| | — |
| | 8 |
| | |
| Uranium | Other deferred credits and liabilities | | 1 |
| | 1 |
| | — |
| | MTM derivative liabilities | | (b) |
| | — |
| | 1 |
|
| | Total liabilities | $ | 280 |
| $ | 37 |
| $ | 386 |
| | Other current liabilities | | 1 |
| | — |
| | — |
|
| | | Other deferred credits and liabilities | | 1 |
| | — |
| | 1 |
|
| | | Total liabilities | $ | 25 |
| $ | 205 |
| $ | 230 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.derivatives subject to regulatory deferral. |
| |
| (b) | Balance sheet line item not applicable to registrant. |
| |
(c) | Includes derivatives subject to regulatory deferral. |
The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred in accumulated OCI and regulatory assets or regulatory liabilities as of December 31, 2012,2013, and 2011:2012:
|
| | | | | | | | | | | | | | | | |
| | | Ameren | | Ameren Missouri | | Ameren Illinois | | Other(a) |
| 2012 | | | | | | | | |
| Cumulative gains (losses) deferred in accumulated OCI: | | | | | | | | |
Power derivative contracts(b) | | $ | 47 |
| | $ | — |
| | $ | — |
| | $ | 47 |
|
Interest rate derivative contracts(c)(d) | | (7 | ) | | — |
| | — |
| | (7 | ) |
| Cumulative gains (losses) deferred in regulatory liabilities or assets: | | | | | | | | |
Fuel oils derivative contracts(e) | | 4 |
| | 4 |
| | — |
| | — |
|
Natural gas derivative contracts(f) | | (107 | ) | | (14 | ) | | (93 | ) | | — |
|
Power derivative contracts(g) | | (99 | ) | | 12 |
| | (111 | ) | | — |
|
Uranium derivative contracts(f) | | (2 | ) | | (2 | ) | | — |
| | — |
|
| 2011 | | | | | | | | |
| Cumulative gains (losses) deferred in accumulated OCI: | | | | | | | | |
Power derivative contracts(b) | | $ | 19 |
| | $ | — |
| | $ | — |
| | $ | 19 |
|
Interest rate derivative contracts(c)(d) | | (8 | ) | | — |
| | — |
| | (8 | ) |
| Cumulative gains (losses) deferred in regulatory liabilities or assets: | | | | | | | | |
Fuel oils derivative contracts(e) | | 19 |
| | 19 |
| | — |
| | — |
|
Natural gas derivative contracts(f) | | (191 | ) | | (24 | ) | | (167 | ) | | — |
|
Power derivative contracts(g) | | 81 |
| | 21 |
| | (140 | ) | | 200 |
|
Uranium derivative contracts(h) | | (1 | ) | | (1 | ) | | — |
| | — |
|
|
| | | | | | | | | |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2013 | | | | | | |
| Cumulative gains (losses) deferred in regulatory liabilities or assets: | | | | | | |
Fuel oils derivative contracts(a) | $ | 2 |
| $ | — |
| $ | 2 |
|
Natural gas derivative contracts(b) | | (10 | ) | | (45 | ) | | (55 | ) |
Power derivative contracts(c) | | 19 |
| | (108 | ) | | (89 | ) |
Uranium derivative contracts(d) | | (6 | ) | | — |
| | (6 | ) |
| 2012 | | | | | | |
| Cumulative gains (losses) deferred in regulatory liabilities or assets: | | | | | | |
Fuel oils derivative contracts(a) | $ | 4 |
| $ | — |
| $ | 4 |
|
Natural gas derivative contracts(b) | | (14 | ) | | (93 | ) | | (107 | ) |
Power derivative contracts(c) | | 12 |
| | (111 | ) | | (99 | ) |
Uranium derivative contracts(d) | | (2 | ) | | — |
| | (2 | ) |
| |
| (a) | Includes amounts for Marketing Company, Genco, and intercompany eliminations. |
| |
(b) | Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through December 2016 as of December 31, 2012. In light of market prices at December 31, 2012, net pretax unrealized gains of $32 million are expected to be reclassified into earnings during the next 12 months as the hedged transaction occur. However, the actual amount reclassified from accumulated OCI could vary due to future changes in market prices.
|
| |
(c) | Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps covered the first 10 years of debt that has a 30-year maturity, and the gain in OCI was amortized over a 10-year period that began in June 2002. The balance of the gain was fully amortized as of June 30, 2012. The carrying value at December 31, 2011, was less than $1 million.
|
| |
(d) | Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco's April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at December 31, 2012, and December 31, 2011, was a loss of $8 million and $9 million, respectively. Over the next twelve months ending December 31, 2013, $1.4 million of the loss will be amortized.
|
| |
(e) | Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through October 20152016, as of December 31, 2012.2013. Current gains deferred as regulatory liabilities include $43 million and $43 million at Ameren and Ameren Missouri as of December 31, 2012,2013, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2012,2013, respectively. |
| |
(f)(b) | Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2017October 2019 at Ameren and Ameren Missouri and through October 2016March 2017 at Ameren Illinois, in each case as of December 31, 2012.2013. Current gains deferred as regulatory liabilities include $12 million, $1 million, and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2012. Current losses deferred as regulatory assets include $64 million, $8 million, and $56 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of December 31, 2012.2013. Current losses deferred as regulatory assets include $32 million, $5 million, and $27 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2013. |
| |
(g)(c) | Represents net lossesgains (losses) associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of December 31, 2012.2013. Current gains deferred as regulatory liabilities include $1423 million and $1423 million at Ameren and Ameren Missouri, respectively, as of December 31, 2012.2013. Current losses deferred as regulatory assets include $2413 million, $34 million, and $219 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2012.2013. |
| |
(h)(d) | Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's uranium requirements through September 2014October 2016, as of December 31, 2012.2013. Current losses deferred as regulatory assets include $15 million and $15 million at Ameren and Ameren Missouri as of December 31, 2012,2013, respectively. |
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 Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master trading and netting agreement level by counterparty.
Although Ameren had not previously elected to offset fair value amounts and collateral for derivative instruments executed with the same counterparty under the same master netting arrangement, authoritative accounting guidance, effective in the first quarter 2013, requires those amounts eligible to be offset to be presented both at the gross and net amounts. The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of December 31, 2013, and 2012:
|
| | | | | | | | | | | | |
| | | | | Gross Amounts Not Offset in the Balance Sheet | | |
| | | Gross Amounts Recognized in the Balance Sheet | | Derivative Instruments | | Cash Collateral Received/Posted(a) | | Net Amount |
| 2013 | | | | | | | | |
| Commodity contracts eligible to be offset: | | | | | | | | |
| Assets: | | | | | | | | |
| Ameren Missouri | $ | 33 |
| $ | 9 |
| $ | — |
| $ | 24 |
|
| Ameren Illinois | | 1 |
| | 1 |
| | — |
| | — |
|
| Ameren | $ | 34 |
| $ | 10 |
| $ | — |
| $ | 24 |
|
| Liabilities: | | | | | | | | |
| Ameren Missouri | $ | 24 |
| $ | 9 |
| $ | 9 |
| $ | 6 |
|
| Ameren Illinois | | 154 |
| | 1 |
| | 15 |
| | 138 |
|
| Ameren | $ | 178 |
| $ | 10 |
| $ | 24 |
| $ | 144 |
|
| 2012 | | | | | | | | |
| Commodity contracts eligible to be offset: | | | | | | | | |
| Assets: | | | | | | | | |
| Ameren Missouri | $ | 28 |
| $ | 9 |
| $ | — |
| $ | 19 |
|
| Ameren Illinois | | 1 |
| | 1 |
| | — |
| | — |
|
| Ameren | $ | 29 |
| $ | 10 |
| $ | — |
| $ | 19 |
|
| Liabilities: | | | | | | | | |
| Ameren Missouri | $ | 25 |
| $ | 9 |
| $ | 7 |
| $ | 9 |
|
| Ameren Illinois | | 205 |
| | 1 |
| | 58 |
| | 146 |
|
| Ameren | $ | 230 |
| $ | 10 |
| $ | 65 |
| $ | 155 |
|
| |
(a) | Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet. |
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 by groupings theWe calculate maximum exposure, as of December 31, 2012, and 2011, if counterparty groups were to fail completely to perform on contracts. The maximum exposure isexposures based on the gross fair value of financial instruments, including accrual and NPNS contracts. As of December 31, 2013, if counterparty groups were to fail completely to perform on contracts, which excludes collateral held,Ameren, Ameren Missouri, and does not consider the legally binding rightAmeren Illinois' maximum exposure was $13 million, $12 million, and $1 million, respectively. As of December 31, 2012, if counterparty groups were to net transactions basedfail completely to perform on master tradingcontracts, Ameren, Ameren Missouri, and netting agreements.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Affiliates(a) | | Coal Producers | | Commodity Marketing Companies | | Electric Utilities | | Financial Companies | | Municipalities/ Cooperatives | | Oil and Gas Companies | | Retail Companies | | Total |
| 2012 | | | | | | | | | | | | | | | | | |
| AMO | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 3 |
| | $ | 14 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
| AIC | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Other(b) | 71 |
| | 3 |
| | 38 |
| | 10 |
| | 13 |
| | 192 |
| | 3 |
| | 85 |
| | 415 |
|
| Ameren | $ | 71 |
| | $ | 3 |
| | $ | 40 |
| | $ | 13 |
| | $ | 28 |
| | $ | 195 |
| | $ | 3 |
| | $ | 85 |
| | $ | 438 |
|
| 2011 | | | | | | | | | | | | | | | | | |
| AMO | $ | 1 |
| | $ | 35 |
| | $ | 1 |
| | $ | 4 |
| | $ | 26 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 71 |
|
| AIC | — |
| | — |
| | 84 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | 85 |
|
Other(b) | 275 |
| | 2 |
| | 4 |
| | 12 |
| | 57 |
| | 194 |
| | 3 |
| | 87 |
| | 634 |
|
| Ameren | $ | 276 |
| | $ | 37 |
| | $ | 89 |
| | $ | 16 |
| | $ | 84 |
| | $ | 198 |
| | $ | 3 |
| | $ | 87 |
| | $ | 790 |
|
| |
(a) | Primarily composed of Marketing Company’s exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level for purposes of this disclosure as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 - Related Party Transactions for additional information on these financial contracts. |
| |
(b) | Includes amounts for Marketing Company, AERG, Genco, and AFS. |
Ameren Illinois' maximum exposure was $23 million, $22 million, and $1 million, respectively. The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by Ameren and Marketing Company from counterparties and based on contractual rights under agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements was $3 million from commodity marketing companies at December 31, 2012. Cash collateral held by Ameren and Marketing Company was less than $1 million and less than $1 million, respectively, from retail companies at December 31, 2011. As of December 31, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of $7 million, $1 million, and $6 million held by Ameren, Ameren Missouri, and Marketing Company, respectively. As of December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million, $1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco and Marketing Company, respectively. The following table presents2013, the potential loss after consideration of the application of master trading and netting agreements and collateral held asfor Ameren and Ameren Missouri was $6 million and $6 million, respectively. As of December 31, 2012, the potential loss after consideration of the application of master trading and 2011:netting agreements and collateral held for Ameren and Ameren Missouri was $15 million and $15 million, respectively.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Affiliates(a) | | Coal Producers | | Commodity Marketing Companies | | Electric Utilities | | Financial Companies | | Municipalities/ Cooperatives | | Oil and Gas Companies | | Retail Companies | | Total |
| 2012 | | | | | | | | | | | | | | | | | |
| AMO | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | 10 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| AIC | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other(b) | 68 |
| | 1 |
| | 29 |
| | 4 |
| | 11 |
| | 185 |
| | — |
| | 85 |
| | 383 |
|
| Ameren | $ | 68 |
| | $ | 1 |
| | $ | 30 |
| | $ | 5 |
| | $ | 21 |
| | $ | 188 |
| | $ | — |
| | $ | 85 |
| | $ | 398 |
|
| 2011 | | | | | | | | | | | | | | | | | |
| AMO | $ | 1 |
| | $ | 35 |
| | $ | 1 |
| | $ | 3 |
| | $ | 22 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 66 |
|
| AIC | — |
| | — |
| | 84 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 84 |
|
Other(b) | 273 |
| | — |
| | 3 |
| | 6 |
| | 43 |
| | 187 |
| | 2 |
| | 86 |
| | 600 |
|
| Ameren | $ | 274 |
| | $ | 35 |
| | $ | 88 |
| | $ | 9 |
| | $ | 65 |
| | $ | 191 |
| | $ | 2 |
| | $ | 86 |
| | $ | 750 |
|
| |
(a) | Primarily composed of Marketing Company’s exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level for purposes of this disclosure as it is calculated without regard to the offsetting affiliate counterparty’s liability position. See Note 14 - Related Party Transactions for additional information on these financial contracts. |
| |
(b) | Includes amounts for Marketing Company, AERG, Genco, and AFS. |
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, 2012,2013, and 2011,2012, 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, 2012,2013, or 2011,2012, respectively, and (2) those counterparties with rights to do so requested collateral:
| | | | Aggregate Fair Value of Derivative Liabilities(a) | | Cash Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) | Aggregate Fair Value of Derivative Liabilities(a) | | Cash Collateral Posted | | Potential Aggregate Amount of Additional Collateral Required(b) |
| 2013 | | | | | | |
| Ameren Missouri | | $ | 70 |
| | $ | 2 |
| | $ | 67 |
|
| Ameren Illinois | | 75 |
| | 15 |
| | 55 |
|
| Ameren | | $ | 145 |
| | $ | 17 |
| | $ | 122 |
|
| 2012 | | | | | | | | | | |
| Ameren Missouri | $ | 78 |
| | $ | 3 |
| | $ | 71 |
| $ | 78 |
| | $ | 3 |
| | $ | 71 |
|
| Ameren Illinois | 148 |
| | 58 |
| | 84 |
| 148 |
| | 58 |
| | 84 |
|
Other(c) | 130 |
| | 7 |
| | 90 |
| |
| Ameren | $ | 356 |
| | $ | 68 |
| | $ | 245 |
| $ | 226 |
| | $ | 61 |
| | $ | 155 |
|
| 2011 | | | | | | |
| Ameren Missouri | $ | 102 |
| | $ | 8 |
| | $ | 86 |
| |
| Ameren Illinois | 220 |
| | 96 |
| | 125 |
| |
Other(c) | 134 |
| | 12 |
| | 121 |
| |
| Ameren | $ | 456 |
| | $ | 116 |
| | $ | 332 |
| |
| |
| (a) | Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures. |
| |
| (b) | As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements. |
| |
(c) | Includes amounts for Marketing Company, Genco, and Ameren (parent). |
Cash Flow Hedges
The following table presents the pretax net gain or loss for the year ended December 31, 2012 and 2011, associated with derivative instruments designated as cash flow hedges:
|
| | | | | | | | | | | | | | | |
| | Gain (Loss) Recognized in OCI(a) | | Location of (Gain) Loss Reclassified from Accumulated OCI into Income(b) | | (Gain) Loss Reclassified from Accumulated OCI into Income(b) | | Location of Gain (Loss) Recognized in Income(c) | | Gain (Loss) Recognized in Income(c) |
| 2012 | | | | | | | | | |
Ameren:(d) | | | | | | | | | |
| Power | $ | 34 |
| | Operating Revenues - Electric | | $ | (6 | ) | | Operating Revenues - Electric | | $ | (12 | ) |
Interest rate(e) | — |
| | Interest Charges | | 1 |
| | Interest Charges | | — |
|
| 2011 | | | | | | | | | |
Ameren:(d) | | | | | | | | | |
| Power | $ | 6 |
| | Operating Revenues - Electric | | $ | 5 |
| | Operating Revenues - Electric | | $ | (10 | ) |
Interest rate(e) | — |
| | Interest Charges | | (f) |
| | Interest Charges | | — |
|
| |
(a) | Effective portion of gain (loss). |
| |
(b) | Effective portion of (gain) loss on settlements. |
| |
(c) | Ineffective portion of gain (loss) and amount excluded from effectiveness testing. |
| |
(d) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(e) | Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period. |
Other Derivatives
The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the years ended December 31, 2012 and 2011:
|
| | | | | | | | | | | |
| | | | Location of Gain (Loss) Recognized in Income | | Gain (Loss) Recognized in Income |
| | | 2012 | | 2011 |
Ameren(a) | Coal | | Operating Expenses - Fuel | | $ | (12 | ) | | $ | — |
|
| | Fuel oils | | Operating Expenses - Fuel | | (11 | ) | | (1 | ) |
| | Natural gas (generation) | | Operating Expenses - Fuel | | 1 |
| | 2 |
|
| | Power | | Operating Revenues - Electric | | 12 |
| | (2 | ) |
| | | | Total | | $ | (10 | ) | | $ | (1 | ) |
| Ameren Missouri | Natural gas (generation) | | Operating Expenses - Fuel | | $ | — |
| | $ | (1 | ) |
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
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 years ended December 31, 20122013 and 20112012:
|
| | | | | | | | | |
| | | Gain (Loss) Recognized In Regulatory Liabilities or Regulatory Assets |
| 2012 | | 2011 |
Ameren (a) | Fuel oils | | $ | (15 | ) | | $ | — |
|
| | Natural gas | | 84 |
| | (26 | ) |
| | Power | | (180 | ) | | 80 |
|
| | Uranium | | (1 | ) | | (3 | ) |
| | Total | | $ | (112 | ) | | $ | 51 |
|
| Ameren | Fuel oils | | $ | (15 | ) | | $ | — |
|
| Missouri | Natural gas | | 10 |
| | — |
|
| | Power | | (9 | ) | | 18 |
|
| | Uranium | | (1 | ) | | (3 | ) |
| | Total | | $ | (15 | ) | | $ | 15 |
|
| Ameren | Natural gas | | $ | 74 |
| | $ | (26 | ) |
| Illinois | Power | | 29 |
| | 212 |
|
| | Total | | $ | 103 |
| | $ | 186 |
|
|
| | | | | | | | | |
| | | Gain (Loss) Recognized in Regulatory Liabilities or Regulatory Assets |
| 2013 | | 2012 |
Ameren (a) | Fuel oils | | $ | (2 | ) | | $ | (15 | ) |
| | Natural gas | | 52 |
| | 84 |
|
| | Power | | 10 |
| | (180 | ) |
| | Uranium | | (4 | ) | | (1 | ) |
| | Total | | $ | 56 |
| | $ | (112 | ) |
| Ameren Missouri | Fuel oils | | $ | (2 | ) | | $ | (15 | ) |
| | Natural gas | | 4 |
| | 10 |
|
| | Power | | 7 |
| | (9 | ) |
| | Uranium | | (4 | ) | | (1 | ) |
| | Total | | $ | 5 |
| | $ | (15 | ) |
| Ameren Illinois | Natural gas | | $ | 48 |
| | $ | 74 |
|
| | Power | | 3 |
| | 29 |
|
| | Total | | $ | 51 |
| | $ | 103 |
|
As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, Ameren Illinois entered into financial contracts with Marketing Company. These financial contracts were derivative instruments. They were accounted for as cash flow hedges by Marketing Company and as derivatives that qualified for regulatory deferral by Ameren Illinois. Consequently, Ameren Illinois and Marketing Company recorded the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by Ameren Illinois and OCI by Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the derivative instruments entered into among affiliates were eliminated. As of December 31, 2012 these contracts had fully expired. The fair value of the financial contracts included in "MTM derivative liabilities - affiliates" on Ameren Illinois' balance sheet was $200 million at December 31, 2011.
| |
| (a) | Includes amounts forAmounts include intercompany eliminations. |
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 1: Inputs based on quoted prices in active markets for
identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri’s nuclear decommissioning trust fund.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri's nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index comprises stocks of large capitalization companies.
Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including corporate bonds and other fixed-income securities, United States treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power
transactions.
Fixed income securities are valued using prices from independent industry recognized data vendors who provide values that are either exchange basedexchange-based or matrix based.matrix-based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the nuclear decommissioning trust fund are primarily corporate bonds, asset-backed securities and United States agency bonds.
Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. 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. Natural gas derivative contracts are valued based upon
exchange closing prices without significant unobservable adjustments. Power derivatives contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.
Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails
obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors. Note 17 - Impairment and Other Charges describes Ameren's use of significant unobservable inputs, which are Level 3 inputs, to estimate the fair value of Merchant Generation's long-lived assets.
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.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:2013:
| | | | | Fair Value | | Range [Weighted | | Fair Value | | Weighted |
| | | Assets | Liabilities | Valuation Technique(s) | Unobservable Input | Average] | | Assets | Liabilities | Valuation Technique(s) | Unobservable Input | Range | Average |
Level 3 Derivative asset and liability - commodity contracts(a): | | |
Level 3 Derivative asset and liability – commodity contracts(a): | | Level 3 Derivative asset and liability – commodity contracts(a): | |
Ameren(b) | Fuel oils | $ | 9 |
| $ | (3 | ) | Discounted cash flow | Escalation rate(%)(c) | .21 - .68 [.48] | Fuel oils | $ | 8 |
| $ | (3 | ) | Option model | Volatilities(%)(b) | 10 - 35 | 16 |
| | | | | Counterparty credit risk(%)(d),(e) | .12 - 1 [1] | |
| | | | | Ameren credit risk(%)(d),(e) | 2 - 31 [12] | |
| | | | Option model | Volatilities(%)(c) | 7 - 27 [24] | |
| | Power(f) | 131 |
| (172 | ) | Option model | Volatilities(%)(d) | 13 - 38 [26] | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.26 - 2 | 1 |
| | | | | Average bid/ask consensus peak and off-peak pricing($/MWh)(d) | 24 - 45 [36] | Power(e) | 21 |
| (110 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c) | 25 - 51 | 32 |
| | | | Discounted cash flow | Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(d) | 16 - 52 [32] | | | | Estimated auction price for FTRs($/MW)(b) | (1,594) - 945 | 305 |
| | | | | Estimated auction price for FTRs($/MW)(c) | (133,787) - 19,671 [198] | | | | Nodal basis($/MWh)(c) | (3) - (1) | (2) |
| | | | | Nodal basis($/MWh)(d) | (12) - 1 [(1)] | | | | Counterparty credit risk(%)(c)(d) | 0.39 - 0.50 | 0.42 |
| | | | | Counterparty credit risk(%)(d),(e) | .04 - 100 [2] | | | | Ameren credit risk(%)(c)(d) | 2 | (f) |
| | | | | Ameren credit risk(%)(d),(e) | 2 - 5 [5] | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 5 | 5 |
| | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(c) | 4 - 8 [6] | | | | Escalation rate(%)(b)(g) | 3 - 4 | 4 |
| | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(c) | 5 - 7 [6] | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
| | Uranium | — |
| (2 | ) | Discounted cash flow | Average bid/ask consensus pricing($/pound)(c) | 43 - 46 [44] | Uranium | — |
| (6 | ) | Discounted cash flow | Average bid/ask consensus pricing($/pound)(b) | 34 - 41 | 36 |
| Ameren Missouri | Fuel oils | $ | 8 |
| $ | (3 | ) | Discounted cash flow | Escalation rate(%)(c) | .21 - .60 [.44] | Fuel oils | $ | 8 |
| $ | (3 | ) | Option model | Volatilities(%)(b) | 10 - 35 | 16 |
| | | | | Counterparty credit risk(%)(d),(e) | .12 - 1 [1] | | | Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.26 - 2 | 1 |
| | | | | Ameren Missouri credit risk(%)(d),(e) | 2 | Power(e) | 21 |
| (2 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c) | 25 - 51 | 40 |
| | | | Option model | Volatilities(%)(c) | 7 - 27 [24] | | | | Estimated auction price for FTRs($/MW)(b) | (1,594) - 945 | 305 |
| | Power(f) | 14 |
| (3 | ) | Discounted cash flow | Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(d) | 24 - 56 [36] | | | | Nodal basis($/MWh)(c) | (3) - (1) | (2) |
| | | | | Estimated auction price for FTRs($/MW)(c) | (281) - 1,851 [178] | | | | Counterparty credit risk(%)(c)(d) | 0.39 - 0.50 | 0.42 |
| | | | | Nodal basis($/MWh)(d) | (5) - (1) [(2)] | | | | Ameren Missouri credit risk(%)(c)(d) | 2 | (f) |
| | | | | Counterparty credit risk(%)(d),(e) | .22 - 1 [1] | Uranium | — |
| (6 | ) | Discounted cash flow | Average bid/ask consensus pricing($/pound)(b) | 34 - 41 | 36 |
| | | | | Ameren Missouri credit risk(%)(d),(e) | 2 | |
| | Uranium | — |
| (2 | ) | Discounted cash flow | Average bid/ask consensus pricing($/pound)(c) | 43 - 46 [44] | |
| Ameren Illinois | Power(f) | $ | — |
| $ | (111 | ) | Discounted cash flow | Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c) | 22 - 47 [30] | Power(e) | $ | — |
| $ | (108 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b) | 27 - 36 | 30 |
| | | | | Nodal basis($/MWh)(c) | (5) - (1) [(3)] | | | | Nodal basis($/MWh)(b) | (4) - 0 | (2) |
| | | | | Ameren Illinois credit risk(%)(d),(e) | 5 | | | | Ameren Illinois credit risk(%)(c)(d) | 2 | (f) |
| | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(c) | 4 - 8 [6] | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 5 | 5 |
| | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(c) | 5 - 7 [6] | | | | Escalation rate(%)(b)(g) | 3 - 4 | 4 |
| | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
| |
| (a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
| (b) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
| |
| (c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
| |
| (d) | Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren, Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances. |
| |
| (e) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 use fundamentally modeled pricing by month for peak and off-peak demand. |
| |
| (g) | Escalation rate applies to power prices 2026 and beyond. |
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012:
|
| | | | | | | | | | | |
| | | Fair Value | | | | Weighted |
| | | Assets | Liabilities | Valuation Technique | Unobservable Input | Range | Average |
Level 3 Derivative asset and liability – commodity contracts(a): | | | |
| Ameren | Fuel oils | $ | 8 |
| $ | (3 | ) | Option model | Volatilities(%)(b) | 7 - 27 | 24 |
| | | | | Discounted cash flow | Escalation rate(%)(b) | 0.21 - 0.60 | 0.44 |
| | | | | | Counterparty credit risk(%)(c)(d) | 0.12 - 1 | 1 |
| | | | | | Ameren credit risk(%)(c)(d) | 2 | (e) |
| | Power(f) | 14 |
| (114 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c) | 22 - 47 | 31 |
| | | | | | Estimated auction price for FTRs($/MW)(b) | (281) - 1,851 | 178 |
| | | | | | Nodal basis($/MWh)(c) | (5) - (1) | (3) |
| | | | | | Counterparty credit risk(%)(c)(d) | 0.22 - 1 | 1 |
| | | | | | Ameren credit risk(%)(c)(d) | 2 - 5 | 5 |
| | | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 8 | 6 |
| | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
| | Uranium | — |
| (2 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 43 - 46 | 44 |
| Ameren Missouri | Fuel oils | $ | 8 |
| $ | (3 | ) | Option model | Volatilities(%)(b) | 7 - 27 | 24 |
| | | | | Discounted cash flow | Escalation rate(%)(b) | 0.21 - 0.60 | 0.44 |
| | | | | | Counterparty credit risk(%)(c)(d) | 0.12 - 1 | 1 |
| | | | | | Ameren Missouri credit risk(%)(c)(d) | 2 | (e) |
| | Power(f) | 14 |
| (3 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c) | 24 - 56 | 36 |
| | | | | | Estimated auction price for FTRs($/MW)(b) | (281) - 1,851 | 178 |
| | | | | | Nodal basis($/MWh)(c) | (5) - (1) | (2) |
| | | | | | Counterparty credit risk(%)(c)(d) | 0.22 - 1 | 1 |
| | | | | | Ameren Missouri credit risk(%)(c)(d) | 2 | (e) |
| | Uranium | — |
| (2 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 43 - 46 | 44 |
| Ameren Illinois | Power(f) | $ | — |
| $ | (111 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(b) | 22 - 47 | 30 |
| | | | | | Nodal basis($/MWh)(b) | (5) - (1) | (3) |
| | | | | | Ameren Illinois credit risk(%)(c)(d) | 5 | (e) |
| | | | | Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 8 | 6 |
| | | | | Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
| |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
| (b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
| |
(d)(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
| |
(e)(d) | Counterparty credit risk is applied only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri and Ameren Illinois credit risk is applied only applied to counterparties with derivative liability balances. |
| |
| (f) | Power valuations utilizeuse visible third partythird-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilizeuse fundamentally modeled pricing by month for peak and off-peak.off-peak demand. |
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 netno gains or losses ofrelated to valuation adjustments for counterparty default risk in 2013, 2012 or 2011. At December 31, 2013, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $3 million, less than $1 million, net losses ofand $23 million, for Ameren, Ameren Missouri, and net gains of less than $1 million in 2012, 2011, and 2010, respectively, related to valuation adjustments for counterparty
default risk in 2012, 2011 and 2010.Ameren Illinois, respectively. At December 31, 2012, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million, less than $1 million, and $7 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. At December 31, 2011, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, and $19 million for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
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, 2013:
|
| | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total |
| Assets: | | | | | | | | | |
| Ameren | Derivative assets – commodity contracts(a): | | | | | | | | |
| | Fuel oils | | $ | 1 |
| | $ | — |
| | $ | 8 |
| | $ | 9 |
|
| | Natural gas | | — |
| | 2 |
| | — |
| | 2 |
|
| | Power | | — |
| | 2 |
| | 21 |
| | 23 |
|
| | Total derivative assets – commodity contracts | | $ | 1 |
| | $ | 4 |
| | $ | 29 |
| | $ | 34 |
|
| | Nuclear decommissioning trust fund: | | | | | | | | |
| | Cash and cash equivalents | | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| | Equity securities: | | | | | | | | |
| | U.S. large capitalization | | 332 |
| | — |
| | — |
| | 332 |
|
| | Debt securities: | | | | | | | | |
| | Corporate bonds | | — |
| | 52 |
| | — |
| | 52 |
|
| | Municipal bonds | | — |
| | 2 |
| | — |
| | 2 |
|
| | U.S. treasury and agency securities | | — |
| | 94 |
| | — |
| | 94 |
|
| | Asset-backed securities | | — |
| | 10 |
| | — |
| | 10 |
|
| | Other | | — |
| | 1 |
| | — |
| | 1 |
|
| | Total nuclear decommissioning trust fund | | $ | 335 |
| | $ | 159 |
| | $ | — |
| | $ | 494 |
|
| | Total Ameren | | $ | 336 |
| | $ | 163 |
| | $ | 29 |
| | $ | 528 |
|
| Ameren Missouri | Derivative assets – commodity contracts(a): | | | | | | | | |
| | Fuel oils | | $ | 1 |
| | $ | — |
| | $ | 8 |
| | $ | 9 |
|
| | Natural gas | | — |
| | 1 |
| | — |
| | 1 |
|
| | Power | | — |
| | 2 |
| | 21 |
| | 23 |
|
| | Total derivative assets – commodity contracts | | $ | 1 |
| | $ | 3 |
| | $ | 29 |
| | $ | 33 |
|
| | Nuclear decommissioning trust fund: | | | | | | | | |
| | Cash and cash equivalents | | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| | Equity securities: | | | | | | | | |
| | U.S. large capitalization | | 332 |
| | — |
| | — |
| | 332 |
|
| | Debt securities: | | | | | | | | |
| | Corporate bonds | | — |
| | 52 |
| | — |
| | 52 |
|
| | Municipal bonds | | — |
| | 2 |
| | — |
| | 2 |
|
| | U.S. treasury and agency securities | | — |
| | 94 |
| | — |
| | 94 |
|
| | Asset-backed securities | | — |
| | 10 |
| | — |
| | 10 |
|
| | Other | | — |
| | 1 |
| | — |
| | 1 |
|
| | Total nuclear decommissioning trust fund | | $ | 335 |
| | $ | 159 |
| | $ | — |
| | $ | 494 |
|
| | Total Ameren Missouri | | $ | 336 |
| | $ | 162 |
| | $ | 29 |
| | $ | 527 |
|
| Ameren Illinois | Derivative assets – commodity contracts(a): | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Liabilities: | | | | | | | | | |
| Ameren | Derivative liabilities – commodity contracts(a): | | | | | | | | |
| | Fuel oils | | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | 3 |
|
| | Natural gas | | 3 |
| | 54 |
| | — |
| | 57 |
|
| | Power | | — |
| | 2 |
| | 110 |
| | 112 |
|
| | Uranium | | — |
| | — |
| | 6 |
| | 6 |
|
| | Total Ameren | | $ | 3 |
| | $ | 56 |
| | $ | 119 |
| | $ | 178 |
|
|
| | | | | | | | | | | | | | | | | |
| Ameren Missouri | Derivative liabilities – commodity contracts(a): | | | | | | | | |
| | Fuel oils | | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | 3 |
|
| | Natural gas | | 3 |
| | 8 |
| | — |
| | 11 |
|
| | Power | | — |
| | 2 |
| | 2 |
| | 4 |
|
| | Uranium | | — |
| | — |
| | 6 |
| | 6 |
|
| | Total Ameren Missouri | | $ | 3 |
| | $ | 10 |
| | $ | 11 |
| | $ | 24 |
|
| Ameren Illinois | Derivative liabilities – commodity contracts(a): | | | | | | | | |
| | Natural gas | | $ | — |
| | $ | 46 |
| | $ | — |
| | $ | 46 |
|
| | Power | | — |
| | — |
| | 108 |
| | 108 |
|
| | Total Ameren Illinois | | $ | — |
| | $ | 46 |
| | $ | 108 |
| | $ | 154 |
|
| |
| (a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
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, 2012:
| | | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | |
| Assets: | | | | | | | | | | | | | | | | | |
Ameren(a) | Derivative assets - commodity contracts(b): | | | | | | | | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Coal | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 8 |
| | $ | 12 |
| |
| | Fuel oils | | 6 |
| | — |
| | 9 |
| | 15 |
| Natural gas | | — |
| | 2 |
| | — |
| | 2 |
| |
| | Natural gas | | 4 |
| | 2 |
| | — |
| | 6 |
| Power | | — |
| | 1 |
| | 14 |
| | 15 |
| |
| | Power | | — |
| | 9 |
| | 131 |
| | 140 |
| Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 3 |
| | $ | 22 |
| | $ | 29 |
| |
| | Total derivative assets - commodity contracts | | $ | 11 |
| | $ | 11 |
| | $ | 140 |
| | $ | 162 |
| Nuclear decommissioning trust fund: | | | | | | | | | |
| | Nuclear decommissioning trust fund(c): | | | | | | | | | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | Cash and cash equivalents | | 1 |
| | — |
| | — |
| | 1 |
| Equity securities: | | | | | | | | | |
| | Equity securities: | | | | | | | | | U.S. large capitalization | | 264 |
| | — |
| | — |
| | 264 |
| |
| | U.S. large capitalization | | 264 |
| | — |
| | — |
| | 264 |
| Debt securities: | | | | | | | | | |
| | Debt securities: | | | | | | | | | Corporate bonds | | — |
| | 47 |
| | — |
| | 47 |
| |
| | Corporate bonds | | — |
| | 47 |
| | — |
| | 47 |
| Municipal bonds | | — |
| | 1 |
| | — |
| | 1 |
| |
| | Municipal bonds | | — |
| | 1 |
| | — |
| | 1 |
| U.S. treasury and agency securities | | — |
| | 81 |
| | — |
| | 81 |
| |
| | U.S. treasury and agency securities | | — |
| | 81 |
| | — |
| | 81 |
| Asset-backed securities | | — |
| | 11 |
| | — |
| | 11 |
| |
| | Asset-backed securities | | — |
| | 11 |
| | — |
| | 11 |
| Other | | — |
| | 1 |
| | — |
| | 1 |
| |
| | Other | | — |
| | 1 |
| | — |
| | 1 |
| Total nuclear decommissioning trust fund | | $ | 265 |
| | $ | 141 |
| | $ | — |
| | $ | 406 |
| (b) |
| | Total nuclear decommissioning trust fund | | $ | 265 |
| | $ | 141 |
| | $ | — |
| | $ | 406 |
| Total Ameren | | $ | 269 |
| | $ | 144 |
| | $ | 22 |
| | $ | 435 |
| |
| Ameren Missouri | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | Total Ameren | | $ | 276 |
| | $ | 152 |
| | $ | 140 |
| | $ | 568 |
| Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 8 |
| | $ | 12 |
| |
| | | Natural gas | | — |
| | 1 |
| | — |
| | 1 |
| |
| | | Power | | — |
| | 1 |
| | 14 |
| | 15 |
| |
| | | Total derivative assets – commodity contracts | | $ | 4 |
| | $ | 2 |
| | $ | 22 |
| | $ | 28 |
| |
| | | Nuclear decommissioning trust fund: | | | | | | | | | |
| | | Cash and cash equivalents | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| | | Equity securities: | | | | | | | | | |
| | | U.S. large capitalization | | 264 |
| | — |
| | — |
| | 264 |
| |
| | | Debt securities: | | | | | | | | | |
| | | Corporate bonds | | — |
| | 47 |
| | — |
| | 47 |
| |
| | | Municipal bonds | | — |
| | 1 |
| | — |
| | 1 |
| |
| | | U.S. treasury and agency securities | | — |
| | 81 |
| | — |
| | 81 |
| |
| | | Asset-backed securities | | — |
| | 11 |
| | — |
| | 11 |
| |
| | | Other | | — |
| | 1 |
| | — |
| | 1 |
| |
| | | Total nuclear decommissioning trust fund | | $ | 265 |
| | $ | 141 |
| | $ | — |
| | $ | 406 |
| (b) |
| | | Total Ameren Missouri | | $ | 269 |
| | $ | 143 |
| | $ | 22 |
| | $ | 434 |
| |
| Ameren Illinois | | Derivative assets – commodity contracts(a): | | | | | | | | | |
| | | Natural gas | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| |
| | | Ameren Missouri | Derivative assets - commodity contracts(b): | | | | | | | | | |
| Fuel oils | | $ | 4 |
| | $ | — |
| | $ | 8 |
| | $ | 12 |
| |
| | Natural gas | | — |
| | 1 |
| | — |
| | 1 |
| |
| | Power | | — |
| | 1 |
| | 14 |
| | 15 |
| |
| | Total derivative assets - commodity contracts | | $ | 4 |
| | $ | 2 |
| | $ | 22 |
| | $ | 28 |
| |
| | Nuclear decommissioning trust fund(c): | | | | | | | | | |
| | Cash and cash equivalents | | 1 |
| | — |
| | — |
| | 1 |
| |
| | Equity securities: | | | | | | | | | |
| | U.S. large capitalization | | 264 |
| | — |
| | — |
| | 264 |
| |
| | Debt securities: | | | | | | | | | |
| | Corporate bonds | | — |
| | 47 |
| | — |
| | 47 |
| |
| | Municipal bonds | | — |
| | 1 |
| | — |
| | 1 |
| |
| | U.S. treasury and agency securities | | — |
| | 81 |
| | — |
| | 81 |
| |
| | Asset-backed securities | | — |
| | 11 |
| | — |
| | 11 |
| |
| | Other | | — |
| | 1 |
| | — |
| | 1 |
| |
| | Total nuclear decommissioning trust fund | | $ | 265 |
| | $ | 141 |
| | $ | — |
| | $ | 406 |
| |
| | Total Ameren Missouri | | $ | 269 |
| | $ | 143 |
| | $ | 22 |
| | $ | 434 |
| |
| Ameren Illinois | Derivative assets - commodity contracts(b): | | | | | | | | | |
| Natural gas | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| |
| | Power | | — |
| | — |
| | — |
| | — |
| |
| | Total Ameren Illinois | | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | | |
Ameren(a) | Derivative liabilities - commodity contracts(b): | | | | | | | | | |
| | Coal | | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | 13 |
| |
| Ameren | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| | Fuel oils | | 3 |
| | — |
| | 3 |
| | 6 |
| Fuel oils | | $ | 1 |
| | $ | — |
| | $ | 3 |
| | $ | 4 |
| |
| | Natural gas | | 11 |
| | 102 |
| | — |
| | 113 |
| Natural gas | | 7 |
| | 102 |
| | — |
| | 109 |
| |
| | Power | | — |
| | 9 |
| | 172 |
| | 181 |
| Power | | — |
| | 1 |
| | 114 |
| | 115 |
| |
| | Uranium | | — |
| | — |
| | 2 |
| | 2 |
| Uranium | | — |
| | — |
| | 2 |
| | 2 |
| |
| | Total Ameren | | $ | 27 |
| | $ | 111 |
| | $ | 177 |
| | $ | 315 |
| Total Ameren | | $ | 8 |
| | $ | 103 |
| | $ | 119 |
| | $ | 230 |
| |
| Ameren Missouri | Derivative liabilities - commodity contracts(b): | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| Fuel oils | | $ | 1 |
| | $ | — |
| | $ | 3 |
| | $ | 4 |
| Fuel oils | | $ | 1 |
| | $ | — |
| | $ | 3 |
| | $ | 4 |
| |
| | Natural gas | | 7 |
| | 8 |
| | — |
| | 15 |
| Natural gas | | 7 |
| | 8 |
| | — |
| | 15 |
| |
| | Power | | — |
| | 1 |
| | 3 |
| | 4 |
| Power | | — |
| | 1 |
| | 3 |
| | 4 |
| |
| | Uranium | | — |
| | — |
| | 2 |
| | 2 |
| Uranium | | — |
| | — |
| | 2 |
| | 2 |
| |
| | Total Ameren Missouri | | $ | 8 |
| | $ | 9 |
| | $ | 8 |
| | $ | 25 |
| Total Ameren Missouri | | $ | 8 |
| | $ | 9 |
| | $ | 8 |
| | $ | 25 |
| |
| Ameren Illinois | Derivative liabilities - commodity contracts(b): | | | | | | | | | Derivative liabilities – commodity contracts(a): | | | | | | | | | |
| Natural gas | | $ | — |
| | $ | 94 |
| | $ | — |
| | $ | 94 |
| Natural gas | | $ | — |
| | $ | 94 |
| | $ | — |
| | $ | 94 |
| |
| | Power | | — |
| | — |
| | 111 |
| | 111 |
| Power | | — |
| | — |
| | 111 |
| | 111 |
| |
| | Total Ameren Illinois | | $ | — |
| | $ | 94 |
| | $ | 111 |
| | $ | 205 |
| Total Ameren Illinois | | $ | — |
| | $ | 94 |
| | $ | 111 |
| | $ | 205 |
| |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
(b) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(c)(b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
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, 2011:
|
| | | | | | | | | | | | | | | | | |
| | | | Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total |
| Assets: | | | | | | | | | |
Ameren(a) | Derivative assets - commodity contracts(b): | | | | | | | | |
| | Fuel oils | | $ | 33 |
| | $ | — |
| | $ | 4 |
| | $ | 37 |
|
| | Natural gas | | 4 |
| | — |
| | 2 |
| | 6 |
|
| | Power | | — |
| | 2 |
| | 193 |
| | 195 |
|
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2013:
|
| | | | | | | | | | | | | | | | | |
| | Total derivative assets - commodity contracts | | $ | 37 |
| | $ | 2 |
| | $ | 199 |
| | $ | 238 |
|
| | Nuclear decommissioning trust fund(c): | | | | | | | | |
| | Cash and cash equivalents | | 3 |
| | — |
| | — |
| | 3 |
|
| | Equity securities: | | | | | | | | |
| | U.S. large capitalization | | 234 |
| | — |
| | — |
| | 234 |
|
| | Debt securities: | | | | | | | | |
| | Corporate bonds | | — |
| | 44 |
| | — |
| | 44 |
|
| | Municipal bonds | | — |
| | 1 |
| | — |
| | 1 |
|
| | U.S. treasury and agency securities | | — |
| | 65 |
| | — |
| | 65 |
|
| | Asset-backed securities | | — |
| | 10 |
| | — |
| | 10 |
|
| | Other | | — |
| | 1 |
| | — |
| | 1 |
|
| | Total nuclear decommissioning trust fund | | $ | 237 |
| | $ | 121 |
| | $ | — |
| | $ | 358 |
|
| | Total Ameren | | $ | 274 |
| | $ | 123 |
| | $ | 199 |
| | $ | 596 |
|
| Ameren Missouri | Derivative assets - commodity contracts(b): | | | | | | | | |
| Fuel oils | | $ | 20 |
| | $ | — |
| | $ | 3 |
| | $ | 23 |
|
| | Natural gas | | 2 |
| | — |
| | — |
| | 2 |
|
| | Power | | — |
| | 1 |
| | 29 |
| | 30 |
|
| | Total derivative assets - commodity contracts | | $ | 22 |
| | $ | 1 |
| | $ | 32 |
| | $ | 55 |
|
| | Nuclear decommissioning trust fund(c): | | | | | | | | |
| | Cash and cash equivalents | | 3 |
| | — |
| | — |
| | 3 |
|
| | Equity securities: | | | | | | | | |
| | U.S. large capitalization | | 234 |
| | — |
| | — |
| | 234 |
|
| | Debt securities: | | | | | | | | |
| | Corporate bonds | | — |
| | 44 |
| | — |
| | 44 |
|
| | Municipal bonds | | — |
| | 1 |
| | — |
| | 1 |
|
| | U.S. treasury and agency securities | | — |
| | 65 |
| | — |
| | 65 |
|
| | Asset-backed securities | | — |
| | 10 |
| | — |
| | 10 |
|
| | Other | | — |
| | 1 |
| | — |
| | 1 |
|
| | Total nuclear decommissioning trust fund | | $ | 237 |
| | $ | 121 |
| | $ | — |
| | $ | 358 |
|
| | Total Ameren Missouri | | $ | 259 |
| | $ | 122 |
| | $ | 32 |
| | $ | 413 |
|
| Ameren Illinois | Derivative assets - commodity contracts(b): | | | | | | | | |
| Natural gas | | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 2 |
|
| | Power | | — |
| | — |
| | 77 |
| | 77 |
|
| | Total Ameren Illinois | | $ | — |
| | $ | — |
| | $ | 79 |
| | $ | 79 |
|
| Liabilities: | | | | | | | | | |
Ameren(a) | Derivative liabilities - commodity contracts(b): | | | | | | | | |
| | Fuel oils | | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
| | Natural gas | | 22 |
| | — |
| | 176 |
| | 198 |
|
| | Power | | — |
| | 2 |
| | 78 |
| | 80 |
|
| | Uranium | | — |
| | — |
| | 1 |
| | 1 |
|
| | Total Ameren | | $ | 24 |
| | $ | 2 |
| | $ | 255 |
| | $ | 281 |
|
| Ameren Missouri | Derivative liabilities - commodity contracts(b): | | | | | | | | |
| Fuel oils | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| | Natural gas | | 12 |
| | — |
| | 14 |
| | 26 |
|
| | Power | | — |
| | 1 |
| | 8 |
| | 9 |
|
| | Uranium | | — |
| | — |
| | 1 |
| | 1 |
|
| | Total Ameren Missouri | | $ | 13 |
| | $ | 1 |
| | $ | 23 |
| | $ | 37 |
|
| Ameren Illinois | Derivative liabilities - commodity contracts(b): | | | | | | | | |
| Natural gas | | $ | 7 |
| | $ | — |
| | $ | 162 |
| | $ | 169 |
|
| | Power | | — |
| | — |
| | 217 |
| | 217 |
|
| | Total Ameren Illinois | | $ | 7 |
| | $ | — |
| | $ | 379 |
| | $ | 386 |
|
|
| | | | | | | | | |
| | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fuel oils: | | | | | | |
| Beginning balance at January 1, 2013 | $ | 5 |
| $ | (a) |
| $ | 5 |
|
| Realized and unrealized gains (losses): | | | | | | |
| Included in regulatory assets/liabilities | | — |
| | (a) |
| | — |
|
| Total realized and unrealized gains (losses) | | — |
| | (a) |
| | — |
|
| Purchases | | 3 |
| | (a) |
| | 3 |
|
| Sales | | (1 | ) | | (a) |
| | (1 | ) |
| Settlements | | (2 | ) | | (a) |
| | (2 | ) |
| Ending balance at December 31, 2013 | $ | 5 |
| $ | (a) |
| $ | 5 |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31,2013 | $ | — |
| $ | (a) |
| $ | — |
|
| Natural gas: | | | | | | |
| Beginning balance at January 1, 2013 | $ | — |
| $ | — |
| $ | — |
|
| Realized and unrealized gains (losses): | | | | | | |
| Included in regulatory assets/liabilities | | — |
| | (1 | ) | | (1 | ) |
| Total realized and unrealized gains (losses) | | — |
| | (1 | ) | | (1 | ) |
| Purchases | | — |
| | 1 |
| | 1 |
|
| Ending balance at December 31, 2013 | $ | — |
| $ | — |
| $ | — |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2013 | $ | — |
| $ | — |
| $ | — |
|
| Power: | | | | | | |
| Beginning balance at January 1, 2013 | $ | 11 |
| $ | (111 | ) | $ | (100 | ) |
| Realized and unrealized gains (losses): | | | | | | |
| Included in regulatory assets/liabilities | | 3 |
| | (18 | ) | | (15 | ) |
| Total realized and unrealized gains (losses) | | 3 |
| | (18 | ) | | (15 | ) |
| Purchases | | 40 |
| | — |
| | 40 |
|
| Settlements | | (36 | ) | | 21 |
| | (15 | ) |
| Transfers into Level 3 | | (3 | ) | | — |
| | (3 | ) |
| Transfers out of Level 3 | | 4 |
| | — |
| | 4 |
|
| Ending balance at December 31, 2013 | $ | 19 |
| $ | (108 | ) | $ | (89 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2013 | $ | (1 | ) | $ | (24 | ) | $ | (25 | ) |
| Uranium: | | | | | | |
| Beginning balance at January 1, 2013 | $ | (2 | ) | $ | (a) |
| $ | (2 | ) |
| Realized and unrealized gains (losses): | | | | | | |
| Included in regulatory assets/liabilities | | (3 | ) | | (a) |
| | (3 | ) |
| Total realized and unrealized gains (losses) | | (3 | ) | | (a) |
| | (3 | ) |
| Purchases | | (2 | ) | | (a) |
| | (2 | ) |
| Settlements | | 1 |
| | (a) |
| | 1 |
|
| Ending balance at December 31, 2013 | $ | (6 | ) | $ | (a) |
| $ | (6 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2013 | $ | (2 | ) | $ | (a) |
| $ | (2 | ) |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.Not applicable. |
| |
(b) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
| |
(c) | Balance excludes $(1) million of receivables, payables, and accrued income, net.
|
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012:
| | | | | Net Derivative Commodity Contracts | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Other(a) | | Ameren | | Ameren Missouri | | Ameren Illinois | | Ameren |
| Fuel oils: | | | | | | | | | | | | | | |
| Beginning balance at January 1, 2012 | $ | 3 |
| $ | (b) |
| $ | 1 |
| $ | 4 |
| $ | 3 |
| $ | (a) |
| $ | 3 |
|
| Realized and unrealized gains (losses): | | | | | | | | | | | | | | |
| Included in regulatory assets/liabilities | | (1 | ) | | (b) |
| | (b) |
| | (1 | ) | | (1 | ) | | (a) |
| | (1 | ) |
| Total realized and unrealized gains (losses) | | (1 | ) | | (b) |
| | (b) |
| | (1 | ) | | (1 | ) | | (a) |
| | (1 | ) |
| Purchases | | 7 |
| | (b) |
| | — |
| | 7 |
| | 7 |
| | (a) |
| | 7 |
|
| Sales | | (3 | ) | | (b) |
| | — |
| | (3 | ) | | (3 | ) | | (a) |
| | (3 | ) |
| Settlements | | (2 | ) | | (b) |
| | — |
| | (2 | ) | | (2 | ) | | (a) |
| | (2 | ) |
| Transfers into Level 3 | | 1 |
| | (b) |
| | 1 |
| | 2 |
| | 1 |
| | (a) |
| | 1 |
|
| Transfers out of Level 3 | | — |
| | (b) |
| | (1 | ) | | (1 | ) | |
| Ending balance at December 31, 2012 | $ | 5 |
| $ | (b) |
| $ | 1 |
| $ | 6 |
| $ | 5 |
| $ | (a) |
| $ | 5 |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31,2012 | $ | (1 | ) | $ | (b) |
| $ | — |
| $ | (1 | ) | |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 | | $ | (1 | ) | $ | (a) |
| $ | (1 | ) |
| Natural gas: | | | | | | | | | | | | | | |
| Beginning balance at January 1, 2012 | $ | (14 | ) | $ | (160 | ) | $ | — |
| $ | (174 | ) | $ | (14 | ) | $ | (160 | ) | $ | (174 | ) |
| Realized and unrealized gains (losses): | | | | | | | | | | | | | | |
| Included in regulatory assets/liabilities | | (2 | ) | | (25 | ) | | (b) |
| | (27 | ) | | (2 | ) | | (25 | ) | | (27 | ) |
| Total realized and unrealized gains (losses) | | (2 | ) | | (25 | ) | | (b) |
| | (27 | ) | | (2 | ) | | (25 | ) | | (27 | ) |
| Purchases | | — |
| | — |
| | 1 |
| | 1 |
| |
| Settlements | | 1 |
| | 15 |
| | (1 | ) | | 15 |
| | 1 |
| | 15 |
| | 16 |
|
| Transfers out of Level 3 | | 15 |
| | 170 |
| | — |
| | 185 |
| | 15 |
| | 170 |
| | 185 |
|
| Ending balance at December 31, 2012 | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 | $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
| Power: | | | | | | | | | |
Power(b): | | | | | | | |
| Beginning balance at January 1, 2012 | $ | 21 |
| $ | (140 | ) | $ | 234 |
| $ | 115 |
| $ | 21 |
| $ | (140 | ) | $ | 81 |
|
| Realized and unrealized gains (losses): | | | | | | | | | | | | | |
|
Included in earnings(c) | | — |
| | — |
| | 27 |
| | 27 |
| |
| Included in OCI | | — |
| | — |
| | 26 |
| | 26 |
| |
| Included in regulatory assets/liabilities | | 11 |
| | (226 | ) | | 40 |
| | (175 | ) | | 11 |
| | (226 | ) | | (175 | ) |
| Total realized and unrealized gains (losses) | | 11 |
| | (226 | ) | | 93 |
| | (122 | ) | | 11 |
| | (226 | ) | | (175 | ) |
| Purchases | | 21 |
| | — |
| | 8 |
| | 29 |
| | 21 |
| | — |
| | 21 |
|
| Sales | | (1 | ) | | — |
| | 2 |
| | 1 |
| | (1 | ) | | — |
| | (1 | ) |
| Settlements | | (37 | ) | | 255 |
| | (279 | ) | | (61 | ) | | (37 | ) | | 255 |
| | (22 | ) |
| Transfers out of Level 3 | | (4 | ) | | — |
| | 1 |
| | (3 | ) | | (4 | ) | | — |
| | (4 | ) |
| Ending balance at December 31, 2012 | $ | 11 |
| $ | (111 | ) | $ | 59 |
| $ | (41 | ) | $ | 11 |
| $ | (111 | ) | $ | (100 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 | $ | — |
| $ | (191 | ) | (d) $ | 44 |
| $ | (147 | ) | $ | — |
| $ | (191 | ) | (c) $ | (175 | ) |
| Uranium: | | | | | | | | | | | | | | |
| Beginning balance at January 1, 2012 | $ | (1 | ) | $ | (b) |
| $ | (b) |
| $ | (1 | ) | $ | (1 | ) | $ | (a) |
| $ | (1 | ) |
| Realized and unrealized gains (losses): | | | | | | | | | | | | | | |
| Included in regulatory assets/liabilities | | (2 | ) | | (b) |
| | (b) |
| | (2 | ) | | (2 | ) | | (a) |
| | (2 | ) |
| Total realized and unrealized gains (losses) | | (2 | ) | | (b) |
| | (b) |
| | (2 | ) | | (2 | ) | | (a) |
| | (2 | ) |
| Settlements | | 1 |
| | (b) |
| | (b) |
| | 1 |
| | 1 |
| | (a) |
| | 1 |
|
| Ending balance at December 31, 2012 | $ | (2 | ) | $ | (b) |
| $ | (b) |
| $ | (2 | ) | $ | (2 | ) | $ | (a) |
| $ | (2 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2012 | $ | (1 | ) | $ | (b) |
| $ | (b) |
| $ | (1 | ) | $ | (1 | ) | $ | (a) |
| $ | (1 | ) |
| |
| (a) | Includes amounts for Marketing Company, AERG, Genco, and intercompany eliminations, including the elimination of financial power contracts between Ameren Illinois and Marketing Company. |
| |
(c)(b) | Net gains and losses on power derivative commodity contracts are recorded in “Operating Revenues - Electric”.Ameren amounts include intercompany eliminations. |
| |
(d)(c) | The change in unrealized losses was due to decreases in long-term power prices applied to 20-year20-year Ameren Illinois swap contracts, which expire in May 2032. |
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2011:
|
| | | | | | | | | | | | |
| | | Net Derivative Commodity Contracts |
| | | Ameren Missouri | | Ameren Illinois | | Other(a) | | Ameren |
| Fuel oils: | | | | | | | | |
| Beginning balance at January 1, 2011 | $ | 30 |
| $ | (b) |
| $ | 21 |
| $ | 51 |
|
| Realized and unrealized gains (losses): | | | | | | | | |
Included in earnings(c) | | — |
|
| (b) |
| | 16 |
| | 16 |
|
| Included in regulatory assets/liabilities | | 19 |
| | (b) |
| | (b) |
| | 19 |
|
| Total realized and unrealized gains (losses) | | 19 |
| | (b) |
| | 16 |
| | 35 |
|
| Purchases | | 4 |
| | (b) |
| | 1 |
| | 5 |
|
| Sales | | (1 | ) | | (b) |
| | — |
| | (1 | ) |
| Settlements | | (30 | ) | | (b) |
| | (26 | ) | | (56 | ) |
| Transfers out of Level 3 | | (19 | ) | | (b) |
| | (11 | ) | | (30 | ) |
| Ending balance at December 31, 2011 | $ | 3 |
| $ | (b) |
| $ | 1 |
| $ | 4 |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 | $ | (11 | ) | $ | (b) |
| $ | (7 | ) | $ | (18 | ) |
| Natural gas: | | | | | | | | |
| Beginning balance at January 1, 2011 | $ | (14 | ) | $ | (134 | ) | $ | — |
| $ | (148 | ) |
| Realized and unrealized gains (losses): | | | | | | | | |
| Included in regulatory assets/liabilities | | (8 | ) | | (107 | ) | | (b) |
| | (115 | ) |
| Total realized and unrealized gains (losses) | | (8 | ) | | (107 | ) | | (b) |
| | (115 | ) |
| Purchases | | — |
| | 1 |
| | — |
| | 1 |
|
| Sales | | — |
| | (1 | ) | | — |
| | (1 | ) |
| Settlements | | 8 |
| | 81 |
| | — |
| | 89 |
|
| Ending balance at December 31, 2011 | $ | (14 | ) | $ | (160 | ) | $ | — |
| $ | (174 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 | $ | (6 | ) | $ | (72 | ) | $ | — |
| $ | (78 | ) |
| Power: | | | | | | | | |
| Beginning balance at January 1, 2011 | $ | 2 |
| $ | (352 | ) | $ | 386 |
| $ | 36 |
|
| Realized and unrealized gains (losses): | | | | | | | | |
Included in earnings(c) | | — |
| | — |
| | (13 | ) | | (13 | ) |
| Included in OCI | | — |
| | — |
| | 24 |
| | 24 |
|
| Included in regulatory assets/liabilities | | 17 |
| | 7 |
| | 51 |
| | 75 |
|
| Total realized and unrealized gains (losses) | | 17 |
| | 7 |
| | 62 |
| | 86 |
|
| Purchases | | 30 |
| | — |
| | 35 |
| | 65 |
|
| Sales | | (1 | ) | | — |
| | (21 | ) | | (22 | ) |
| Settlements | | (27 | ) | | 205 |
| | (227 | ) | | (49 | ) |
| Transfers into Level 3 | | (1 | ) | | — |
| | 1 |
| | — |
|
| Transfers out of Level 3 | | 1 |
| | — |
| | (2 | ) | | (1 | ) |
| Ending balance at December 31, 2011 | $ | 21 |
| $ | (140 | ) | $ | 234 |
| $ | 115 |
|
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 | $ | 1 |
| $ | 13 |
| $ | 59 |
| $ | 73 |
|
| Uranium: | | | | | | | | |
| Beginning balance at January 1, 2011 | $ | 2 |
| $ | (b) |
| $ | (b) |
| $ | 2 |
|
| Realized and unrealized gains (losses): | | | | | | | | |
| Included in regulatory assets/liabilities | | (3 | ) | | (b) |
| | (b) |
| | (3 | ) |
| Total realized and unrealized gains (losses) | | (3 | ) | | (b) |
| | (b) |
| | (3 | ) |
| Purchases | | (1 | ) | | (b) |
| | (b) |
| | (1 | ) |
| Settlements | | 1 |
| | (b) |
| | (b) |
| | 1 |
|
| Ending balance at December 31, 2011 | $ | (1 | ) | $ | (b) |
| $ | (b) |
| $ | (1 | ) |
| Change in unrealized gains (losses) related to assets/liabilities held at December 31, 2011 | $ | — |
| $ | (b) |
| $ | (b) |
| $ | — |
|
| |
(a) | Includes amounts for Marketing Company, AERG, Genco, and intercompany eliminations, including the elimination of financial power contracts between Ameren Illinois and Marketing Company. |
| |
(c) | Net gains and losses on fuel oils derivative commodity contracts are recorded in "Operating Expenses - Fuel," while net gains and losses on power derivative commodity contracts are recorded in “Operating Revenues - Electric." |
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 out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended December 31, 2012 and the previous reporting period ended December 31, 2011.periods shown below. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the years ended December 31, 20122013 and 20112012, there were no transfers between Level 1 and Level 2 related to
derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the years ended December 31, 20122013 and 20112012:
|
| | | | | | | |
| | 2012 | | 2011 |
Ameren - derivative commodity contracts:(a) |
|
|
|
| Transfers into Level 3 / Transfers out of Level 1 - Fuel oils | $ | 2 |
| | $ | — |
|
| Transfers out of Level 3 / Transfers into Level 1 - Fuel oils | (1 | ) | | (30 | ) |
| Transfers out of Level 3 / Transfers into Level 2 - Natural gas | 185 |
| | — |
|
| Transfers into Level 3 / Transfers out of Level 2 - Power | — |
| | — |
|
| Transfers out of Level 3 / Transfers into Level 2 - Power | (3 | ) | | (1 | ) |
| Net fair value of Level 3 transfers | $ | 183 |
| | $ | (31 | ) |
| Ameren Missouri - derivative commodity contracts: | | | |
| Transfers into Level 3 / Transfers out of Level 1 - Fuel oils | $ | 1 |
| | $ | — |
|
| Transfers out of Level 3 / Transfers into Level 1 - Fuel oils | — |
| | (19 | ) |
| Transfers out of Level 3 / Transfers into Level 2 - Natural gas | 15 |
| | — |
|
| Transfers into Level 3 / Transfers out of Level 2 - Power | — |
| | (1 | ) |
| Transfers out of Level 3 / Transfers into Level 2 - Power | (4 | ) | | 1 |
|
| Net fair value of Level 3 transfers | $ | 12 |
| | $ | (19 | ) |
| Ameren Illinois - derivative commodity contracts: | | | |
| Transfers out of Level 3 / Transfers into Level 2 - Natural gas | $ | 170 |
| | $ | — |
|
|
| | | | | | | |
| | 2013 | | 2012 |
| Ameren - derivative commodity contracts: |
|
|
|
| Transfers into Level 3 / Transfers out of Level 1 – Fuel oils | $ | — |
| | $ | 1 |
|
| Transfers out of Level 3 / Transfers into Level 2 – Natural gas | — |
| | 185 |
|
| Transfers into Level 3 / Transfers out of Level 2 – Power | (3 | ) | | — |
|
| Transfers out of Level 3 / Transfers into Level 2 – Power | 4 |
| | (4 | ) |
| Net fair value of Level 3 transfers | $ | 1 |
| | $ | 182 |
|
| Ameren Missouri - derivative commodity contracts: | | | |
| Transfers into Level 3 / Transfers out of Level 1 – Fuel oils | $ | — |
| | $ | 1 |
|
| Transfers out of Level 3 / Transfers into Level 2 – Natural gas | — |
| | 15 |
|
| Transfers into Level 3 / Transfers out of Level 2 – Power | (3 | ) | | — |
|
| Transfers out of Level 3 / Transfers into Level 2 – Power | 4 |
| | (4 | ) |
| Net fair value of Level 3 transfers | $ | 1 |
| | $ | 12 |
|
| Ameren Illinois - derivative commodity contracts: | | | |
| Transfers out of Level 3 / Transfers into Level 2 – Natural gas | $ | — |
| | $ | 170 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
See Note 11 -– Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 20122013, as well as a table summarizing the changes in Level 3 plan assets during 20122013. See Note 17 - Impairment and Other Charges for the fair value hierarchy discussion related to Ameren's impairment charges.
The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Ameren's and Ameren Missouri's carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the fair value hierarchy as they are valued based on similar market transactions. Short-termThe Ameren Companies' short-term borrowings which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 20122013 and 20112012:
| | | | 2012 | | 2011 | 2013 | �� | 2012 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
Ameren:(b)(a) | | | | | | | | | | | | | | |
| Long-term debt and capital lease obligations (including current portion) | $ | 6,981 |
| | $ | 7,728 |
| | $ | 6,856 |
| | $ | 7,800 |
| $ | 6,038 |
| | $ | 6,584 |
| | $ | 6,157 |
| | $ | 7,110 |
|
| Preferred stock | 142 |
| | 123 |
| | 142 |
| | 92 |
| 142 |
| | 118 |
| | 142 |
| | 123 |
|
| Ameren Missouri: | | | | | | | | | | | | | | |
| Long-term debt and capital lease obligations (including current portion) | $ | 4,006 |
| | $ | 4,625 |
| | $ | 3,950 |
| | $ | 4,541 |
| $ | 3,757 |
| | $ | 4,124 |
| | $ | 4,006 |
| | $ | 4,625 |
|
| Preferred stock | 80 |
| | 73 |
| | 80 |
| | 55 |
| 80 |
| | 71 |
| | 80 |
| | 74 |
|
| Ameren Illinois: | | | | | | | | | | | | | | |
| Long-term debt (including current portion) | $ | 1,727 |
| | $ | 2,020 |
| | $ | 1,658 |
| | $ | 1,943 |
| $ | 1,856 |
| | $ | 2,028 |
| | $ | 1,727 |
| | $ | 2,020 |
|
| Preferred stock | 62 |
| | 49 |
| | 62 |
| | 37 |
| 62 |
| | 47 |
| | 62 |
| | 49 |
|
| Genco: | | | | | | | | |
| Long-term debt (including current portion) | $ | 824 |
| | $ | 618 |
| | $ | 824 |
| | $ | 839 |
| |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
(b) | Preferred stock along with the noncontrolling interest of EEI is recorded in "Noncontrolling Interests" on the consolidated balance sheet. |
NOTE 9 -– NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS
Ameren Missouri has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway energy center. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 20122013, and 20112012. See Note 10 -– Callaway Energy Center for additional information.
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 and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and
losses resulting from those sales for the years ended December 31, 20122013, 20112012, and 20102011:
|
| | | | | | | | | | | |
| | 2012 | | 2011 | | 2010 |
| Proceeds from sales and maturities | $ | 384 |
| | $ | 199 |
| | $ | 256 |
|
| Gross realized gains | 6 |
| | 5 |
| | 5 |
|
| Gross realized losses | 2 |
| | 4 |
| | 4 |
|
|
| | | | | | | | | | | |
| | 2013 | | 2012 | | 2011 |
| Proceeds from sales and maturities | $ | 196 |
| | $ | 384 |
| | $ | 199 |
|
| Gross realized gains | 7 |
| | 6 |
| | 5 |
|
| Gross realized losses | 5 |
| | 2 |
| | 4 |
|
Net realized and unrealized gains and losses are deferred and recorded as regulatory assets or regulatory liabilities on Ameren’s and Ameren Missouri’s balance sheets. This reporting
is consistent with the method used to account for the decommissioning costs recovered in rates. Gains or losses associated with assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which are expected to be reflected in electric rates paid by Ameren Missouri’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 Ameren Missouri’s nuclear decommissioning trust fund at December 31, 20122013, and 20112012:
| | | Security Type | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value | Cost | | Gross Unrealized Gain | | Gross Unrealized Loss | | Fair Value |
| 2013 | | | | | | | | |
| Debt securities | | $ | 157 |
| | $ | 4 |
| $ | 2 |
| | $ | 159 |
|
| Equity securities | | 137 |
| | 199 |
| | 4 |
| | 332 |
|
| Cash | | 3 |
| | — |
| | — |
| | 3 |
|
Other(b) | | (a) |
| | — |
| | — |
| | (a) |
|
| Total | | $ | 297 |
| | $ | 203 |
| $ | 6 |
| | $ | 494 |
|
| 2012 | | | | | | | | | | | | | | |
| Debt securities | $ | 133 |
| | $ | 8 |
| | (a) |
| | $ | 141 |
| $ | 133 |
| | $ | 8 |
| $ | (a) |
| | $ | 141 |
|
| Equity securities | 145 |
| | 130 |
| | 11 |
| | 264 |
| 145 |
| | 130 |
| | 11 |
| | 264 |
|
| Cash | 1 |
| | — |
| | — |
| | 1 |
| 1 |
| | — |
| | — |
| | 1 |
|
Other(b) | 2 |
| | — |
| | — |
| | 2 |
| 2 |
| | — |
| | — |
| | 2 |
|
| Total | $ | 281 |
| | $ | 138 |
| | $ | 11 |
| | $ | 408 |
| $ | 281 |
| | $ | 138 |
| $ | 11 |
| | $ | 408 |
|
| 2011 | | | | | | | | |
| Debt securities | $ | 114 |
| | $ | 7 |
| | (a) |
| | $ | 121 |
| |
| Equity securities | 145 |
| | 101 |
| | 12 |
| | 234 |
| |
| Cash | 3 |
| | — |
| | — |
| | 3 |
| |
Other(b) | (1 | ) | | — |
| | — |
| | (1 | ) | |
| Total | $ | 261 |
| | $ | 108 |
| | $ | 12 |
| | $ | 357 |
| |
| |
| (a) | Amount less than $1 million. |
| |
| (b) | Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest receivables. |
The following table presents the costs and fair values of investments in debt securities in Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 20122013:
| | | | Cost | | Fair Value | Cost | | Fair Value |
| Less than 5 years | $ | 78 |
| | $ | 79 |
| $ | 93 |
| | $ | 94 |
|
| 5 years to 10 years | 32 |
| | 35 |
| 31 |
| | 32 |
|
| Due after 10 years | 23 |
| | 27 |
| 33 |
| | 33 |
|
| Total | $ | 133 |
| | $ | 141 |
| $ | 157 |
| | $ | 159 |
|
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 energy center expires. Ameren Missouri submitted a license extension application to the NRC to extend the Callaway energy center’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 Ameren Missouri'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, 20122013:
| | | | Less than 12 Months | | 12 Months or Greater | | Total | Less than 12 Months | | | 12 Months or Greater | | Total |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| Debt securities | $ | 17 |
| | $ (a) |
| | $ (a) |
| | $ (a) |
| | $ | 17 |
| | $ (a) |
| $ | 72 |
| | $ | 2 |
| | $ | (a) |
| $ | (a) |
| | $ | 72 |
| | $ | 2 |
|
| Equity securities | 7 |
| | 1 |
| | 14 |
| | 10 |
| | 21 |
| | 11 |
| 6 |
| | (a) |
| | | 7 |
| | 4 |
| | 13 |
| | 4 |
|
| Total | $ | 24 |
| | $ | 1 |
| | $ | 14 |
| | $ | 10 |
| | $ | 38 |
| | $ | 11 |
| $ | 78 |
| | $ | 2 |
| | $ | 7 |
| $ | 4 |
| | $ | 85 |
| | $ | 6 |
|
| |
| (a) | Amount less than $1 million. |
NOTE 10 -– CALLAWAY ENERGY CENTER
Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren and other utilities that own and operate those energy centers are
responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated by those plants and sold. The NWPA also requires the DOE to review the nuclear waste
fee against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren Missouri and other utilities have entered into standard contracts with the federal government. The government, represented by the DOE, is responsible for implementing these provisions of the NWPA. Consistent with the NWPA and its standard contract, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center.
Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government has acknowledged since at least 1994 that it would not meet that deadline. The federal government is not currently predicting when it will begin to meetmeeting its disposal obligation. Ameren Missouri has sufficient installed capacity at itsthe Callaway energy center to store theits spent nuclear fuel generated at Callaway through 2020, and it has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s current licensed life.
Until January 2009, the DOE program provided for The DOE's delay in carrying out its obligation to dispose of spent nuclear fuel disposalfrom the Callaway energy center is not expected to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. adversely affect the continued operations of the energy center.
In January 2009, the federal government announced that a spent nuclear fuel repository at Yucca Mountain, Nevada was unworkable andunworkable. The federal government took steps to terminate the Yucca Mountain program, while acknowledging the federal government’sits continuing obligation to dispose of utilities’ spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund.
In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel in response to the recommendation contained in the advisory commission's report.fuel. The DOE's plan calls for a pilot interim storage facility to begin operation with an initial focus on accepting spent nuclear fuel from shutdown reactor sites by 2021. By 2025, a larger interim storage facility would be available, and would be co-located with the pilot facility. The plan also proposes to site a permanent geological repository by 2026, to characterize the site and to design and to license the repository by 2042, and to begin operation by 2048.
In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory
Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit, seeking the suspension of the one mill nuclear waste fee, alleging that the DOE failed to undertake an appropriate fee adequacy review reflecting the current unsettled state of the nuclear waste program. In a June 2012 decision, the court ruled that DOE's fee adequacy review was legally inadequate and remanded the matter to the DOE. Although the court ruled it has the power to direct the DOE to suspend the fee, the court decided that it was premature to do so. Instead, the court ordered the DOE to provide within six months a revised assessment of the amount that should be collected. OnIn January 19, 2013, the DOE issued the revised assessment required by the court. The DOE determined that “neither insufficient nor excess revenues are being collected”collected,” and it proposed no adjustment to the one mill nuclear waste fee. In November 2013, the court rejected the DOE's revised assessment and ordered the DOE to submit a proposal to the United States Congress to reduce the fee to zero. The DOE
The DOE's delay in carrying out its obligation
filed for rehearing, however there is no deadline for the court to dispose of spent nuclear fuel fromact. In January 2014, the Callaway energy center is not expectedDOE, pursuant to adversely affect the continued operation ofcourt's November 2013 order, submitted to Congress a proposal to reduce the energy center.fee to zero.
As a result of the DOE's failure to begin to dispose of the utilities' spent nuclear fuel and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have also sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs that it incurred through 2009. This amount includedIt sought reimbursement for the cost of reracking the Callaway energy center’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had the DOE performed its contractual obligations. In June 2011, the parties reached a settlement agreement that included a payment to Ameren Missouri of $11 million for spent fuel storage and related costs through 20102010. In addition, the settlement agreement provides for annual recovery of additional spent fuel storage and thereafter, annual payment of suchrelated costs after they are incurred from 2011 through 2013 or any otherwith the ability to extend the recovery period as mutually agreed extension.to by the parties. The parties have agreed in principle to extend the recovery period through 2016. As a result of thisthe settlement agreement, Ameren Missouri recorded a pretax reduction of $2 million and $2 million to its “Operating Expenses -– Depreciation and amortization” and “Operating Expenses -– Other operations and maintenance” expense line items, respectively, on its statement of income for the year ended December 31, 2011. Ameren Missouri reduced its property and plant net assets by $7 million for the year ended December 31, 2011.2011. In 2012, Ameren Missouri received thea 2011 cost reimbursement of $1 million and reduced its property"Property and plant, netnet" assets on its balance sheet by this amount inthat amount. In 2013, Ameren Missouri received a 2012 cost reimbursement of 2012$6 million. and reduced its "Property and plant, net" assets on its balance sheet by that amount. In March 2013,2014, Ameren Missouri plans to submit approximately $5$15 million of 20122013 costs to the DOE for reimbursement underpursuant to the settlement agreement. Ameren Missouri reduced its "Property and plant, net" assets by this amount with an offset to "Miscellaneous accounts and notes receivable" on its balance sheet as of December 31, 2013. Included in these reimbursements are costs related to a dry spent fuel storage facility Ameren Missouri is constructing at its Callaway energy center. Ameren Missouri intends to begin transferring spent fuel assemblies to this facility in 2015. Until the facility is completed, Ameren Missouri will, in accordance with the settlement agreement, apply for reimbursement from the DOE for the cost to construct the dry spent fuel storage facility along with related allowable costs.
In December 2011, Ameren Missouri filedsubmitted a license extension application withto the NRC to extend its Callaway energy center's operating license from 2024 to 2044. There is no deadline by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in approving license extensions are rules dealing with the storage of spent nuclear fuel at the reactor site and with the NRC's confidence that permanent disposal of spent nuclear fuel will be available when needed. In a June 2012 decision, the United States Court
of Appeals for the District of Columbia Circuit vacated these rules and remanded the case to the NRC, holding that the NRC's
obligations under the National Environmental Policy Act required a more thorough environmental analysis in support of the NRC's waste confidence decision. In June 2012, a number of groups petitioned the NRC to suspend final licensing decisions in certain NRC licensing proceedings, including the Callaway license extension, until the NRC completed its proceedings on the vacated rules. In August 2012, the NRC stated that it would not issue licenses dependent on the vacated rules until it appropriately addressed the court's remand. In September 2012, the NRC directed its staff to issue, within two years, a generic environmental impact statement and a final rule to address the court's ruling. The NRC also stated that a site-specific analysis of these issues could be conducted in rare circumstances. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility by 2016.
Electric utility rates charged to customers provide for the recovery of the Callaway energy center's decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the nuclear center, ending with the expiration of the energy center's current operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 20122013, 20112012, and 20102011. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. The last cost study and funding analysis were filed with the MoPSC in September 2011. In October 2012, the MoPSC issued an order approving the stipulation and agreement between Ameren Missouri and the MoPSC staff that maintained the current rate of deposits to the trust fund and the rate of return assumptions used in the analysis. If Ameren Missouri's operating license extension application is approved by the NRC, a revised funding analysis will be prepared, and the rates charged to customers will be adjusted accordingly to reflect the operating license extension at the time the next triennial cost study and funding analysis is approved by the MoPSC. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center's decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's and Ameren Missouri's balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value
of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability.
See Note 2 – Rate and Regulatory Matters and Note 9 –
See Note 2 - Rate and Regulatory MattersNuclear Decommissioning Trust Fund Investments for additional information related to the Callaway energy center.
NOTE 11 -– RETIREMENT BENEFITS
The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. Ameren offers defined benefit pension and postretirement benefit plans covering substantially all of its employees. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren Missouri and Ameren Illinois each participate in Ameren’s single-employer pension and other postretirement plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren also has an unfunded non-qualifiednonqualified pension plan, the Ameren Supplemental Retirement Plan, which is available for certain management employees and retirees to provide a supplemental benefit when their qualified pension plan benefits are reducedcapped to comply with Internal Revenue Code limitations. Ameren’s other postretirement plans are the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan. Separately, EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. EEI’s pension plan is the Revised Retirement Plan for Employees of Electric Energy, Inc. EEI’s
other postretirement plans are the Group Insurance Plan for Management Employees of Electric Energy, Inc. and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. Nonaffiliated Ameren companies do not participate in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, or the Ameren Group Life Insurance Plan.
On December 2, 2013, Ameren completed the divestiture of New AER to IPH. In accordance with the transaction agreement, Ameren retained the pension obligations as of December 2, 2013, associated with the current and former employees of New AER and its subsidiaries who were included in the Ameren Retirement Plan and the Ameren Supplemental Retirement Plan. Ameren also retained the postretirement benefit obligations associated with the employees of New AER and its subsidiaries who were eligible to retire at December 2, 2013, from the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan. IPH assumed the existing pension and other postretirement benefit obligations associated with EEI's current and former employees that are included in EEI’s single-employer pension and other postretirement plans. Coincident with Ameren’s divestiture of New AER, a significant number of employees left Ameren consolidates EEI, and therefore, EEI’s plans are reflected inwhich required a measurement of Ameren’s pension and postretirement balancesbenefit plan assets and disclosures.obligations as of December 2, 2013, based upon current market conditions. The reduction in obligations for the postretirement benefit plans and the accelerated recognition of gains previously recorded in accumulated other comprehensive income that had not previously been recognized through net periodic benefit cost for the pension and postretirement benefit plans resulted in a $19 million pretax curtailment gain, which was included in discontinued operations.
The Group Insurance Plan for Bargaining Unit EmployeesAmeren completed another measurement as of Electric Energy, Inc.December 31, 2013, as is its historical accounting practice, based upon the market conditions at the end of the year. Excluding the EEI plans, which were assumed by IPH during 2013, Ameren’s unfunded obligation under its pension and other postretirement benefit plans was over-funded by $14$461 million and $1,143 million as of December 31, 2013, and December 31, 2012, which was included in Ameren's balance sheetrespectively. These net liabilities are recorded in "Other assets.current liabilities," "Pension and other
postretirement benefits," and "Other assets" on Ameren's consolidated balance sheet. The primary factors contributing to this unfunded obligation reduction during 2013 were a 75 basis point increase in the pension and other postretirement benefit plan discount rates used to determine the present value of the obligations, and asset returns being better than expected. The offset to the unfunded obligation reduction was primarily a reduction to "Regulatory assets" on Ameren's consolidated balance sheet.
The following table presents the net benefit liability recorded on the balance sheets of each of the Ameren Companies as of December 31, 2013, and 2012:
| | | | | | 2013 |
| 2012 |
|
Ameren(a) | $ | 1,183 |
| $ | 461 |
| $ | 1,143 |
|
| Ameren Missouri | 464 |
| 191 |
| 464 |
|
| Ameren Illinois | 408 |
| 198 |
| 408 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
Ameren recognizes the under-funded status of its pension and postretirement plans as a liability on its consolidated 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, 20122013, and 20112012. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 20122013, and 20112012, that have not been recognized in net periodic benefit costs.
| | | | 2012 | | 2011 | 2013 | | 2012 |
| | Pension Benefits(a) | | Postretirement Benefits(a) | | Pension Benefits(a) | | Postretirement Benefits(a) | Pension Benefits(a) | | Postretirement Benefits(a) | | Pension Benefits(a) | | Postretirement Benefits(a) |
| Accumulated benefit obligation at end of year | $ | 3,929 |
| | (b) |
| | $ | 3,645 |
| | (b) |
| $ | 3,698 |
| $ | (b) |
| | $ | 3,829 |
| $ | (b) |
|
| Change in benefit obligation: | | | | | | | | | | | | | | |
| Net benefit obligation at beginning of year | $ | 3,865 |
| | $ | 1,257 |
| | $ | 3,451 |
| | $ | 1,120 |
| $ | 4,051 |
| $ | 1,157 |
| | $ | 3,764 |
| $ | 1,145 |
|
| Service cost | 83 |
| | 24 |
| | 75 |
| | 22 |
| 91 |
| | 22 |
| | 81 |
| | 22 |
|
| Interest cost | 170 |
| | 52 |
| | 180 |
| | 58 |
| 163 |
| | 46 |
| | 166 |
| | 47 |
|
Plan amendments(c)(d) | (6 | ) | | (75 | ) | | (16 | ) | | — |
| |
| Participant contributions | — |
| | 16 |
| | — |
| | 18 |
| — |
| | 16 |
| | — |
| | 16 |
|
| Actuarial loss | 246 |
| | 5 |
| | 348 |
| | 96 |
| |
Curtailments(e) | 2 |
| | (1 | ) | | — |
| | — |
| |
| Actuarial (gain) loss | | (207 | ) | | (76 | ) | | 240 |
| | (10 | ) |
Curtailment gain(c) | | — |
| | (3 | ) | | — |
| | — |
|
Settlement(d) | | — |
| | (5 | ) | | — |
| | — |
|
| Benefits paid | (209 | ) | | (73 | ) | | (173 | ) | | (66 | ) | (198 | ) | | (64 | ) | | (200 | ) | | (69 | ) |
| Early retiree reinsurance program receipt | (b) |
| | 2 |
| | (b) |
| | 3 |
| (b) |
| | — |
| | (b) |
| | 2 |
|
| Federal subsidy on benefits paid | (b) |
| | 4 |
| | (b) |
| | 6 |
| (b) |
| | 3 |
| | (b) |
| | 4 |
|
| Net benefit obligation at end of year | 4,151 |
| | 1,211 |
| | 3,865 |
| | 1,257 |
| 3,900 |
| | 1,096 |
| | 4,051 |
| | 1,157 |
|
| Change in plan assets: | | | | | | | | | | | | | | |
| Fair value of plan assets at beginning of year | 2,876 |
| | 896 |
| | 2,722 |
| | 797 |
| 3,127 |
| | 938 |
| | 2,814 |
| | 836 |
|
| Actual return on plan assets | 392 |
| | 110 |
| | 224 |
| | 9 |
| 376 |
| | 156 |
| | 385 |
| | 104 |
|
| Employer contributions | 134 |
| | 45 |
| | 103 |
| | 129 |
| 156 |
| | 25 |
| | 128 |
| | 45 |
|
| Federal subsidy on benefits paid | (b) |
| | 4 |
| | (b) |
| | 6 |
| (b) |
| | 3 |
| | (b) |
| | 4 |
|
| Early retiree reinsurance program receipt | (b) |
| | 2 |
| | (b) |
| | 3 |
| (b) |
| | — |
| | (b) |
| | 2 |
|
| Participant contributions | — |
| | 16 |
| | — |
| | 18 |
| — |
| | 16 |
| | — |
| | 16 |
|
| Benefits paid | (209 | ) | | (73 | ) | | (173 | ) | | (66 | ) | (198 | ) | | (64 | ) | | (200 | ) | | (69 | ) |
| Fair value of plan assets at end of year | 3,193 |
| | 1,000 |
| | 2,876 |
| | 896 |
| 3,461 |
| | 1,074 |
| | 3,127 |
| | 938 |
|
| Funded status - deficiency | 958 |
| | 211 |
| | 989 |
| | 361 |
| |
| Funded status – deficiency | | 439 |
| | 22 |
| | 924 |
| | 219 |
|
| Accrued benefit cost at December 31 | $ | 958 |
| | $ | 211 |
| | $ | 989 |
| | $ | 361 |
| $ | 439 |
| $ | 22 |
| | $ | 924 |
| $ | 219 |
|
| Amounts recognized in the balance sheet consist of: | | | | | | | | | | | | | | |
Noncurrent asset | $ | — |
| | $ | (14 | ) | | $ | — |
| | $ | — |
| $ | — |
| $ | (9 | ) | | $ | — |
| $ | — |
|
Current liability | 3 |
| | 2 |
| | 3 |
| | 3 |
| 3 |
| | 1 |
| | 3 |
| | 2 |
|
| Noncurrent liability | 955 |
| | 223 |
| | 986 |
| | 358 |
| 436 |
| | 30 |
| | 921 |
| | 217 |
|
| Net liability recognized | $ | 958 |
| | $ | 211 |
| | $ | 989 |
| | $ | 361 |
| $ | 439 |
| $ | 22 |
| | $ | 924 |
| $ | 219 |
|
| Amounts recognized in regulatory assets consist of: | | | | | | | | | | | | | | |
| Net actuarial loss | $ | 699 |
| | $ | 103 |
| | $ | 734 |
| | $ | 177 |
| |
| Net actuarial (gain) loss | | $ | 282 |
| $ | (71 | ) | | $ | 699 |
| $ | 103 |
|
| Prior service cost (credit) | (6 | ) | | (24 | ) | | (7 | ) | | (28 | ) | (7 | ) | | (20 | ) | | (6 | ) | | (24 | ) |
| Transition obligation | — |
| | — |
| | — |
| | 2 |
| |
| Amounts (pretax) recognized in accumulated OCI consist of: | | | | | | | | | | | | | | |
| Net actuarial loss | 89 |
| | 51 |
| | 79 |
| | 43 |
| |
| Net actuarial (gain) loss | | 17 |
| | (12 | ) | | 65 |
| | 5 |
|
| Prior service cost (credit) | (17 | ) | | (65 | ) | | (15 | ) | | (7 | ) | — |
| | (1 | ) | | (14 | ) | | (6 | ) |
| Total | $ | 765 |
| | $ | 65 |
| | $ | 791 |
| | $ | 187 |
| $ | 292 |
| $ | (104 | ) | | $ | 744 |
| $ | 78 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
| (c) | In 2012, EEI's pension plan was amendedEffective with the divestiture of New AER on December 2, 2013, the liability for active management employees of New AER and its subsidiaries not eligible to adjustretire were neither transferred to IPH nor retained by Ameren, which resulted in a curtailment gain. See Note 16 – Divestiture Transactions and Discontinued Operations for further information on the calculation of the future benefit obligation for all of its active employees from a traditional, final pay formula to a cash balance formula. Additionally, in 2012, EEI's management and labor union postretirement medical benefit plans were amended to adjust for moving to a Medicare Advantage plan.divestiture. |
| |
| (d) | In 2011, Ameren’s pension planEffective with the divestiture of New AER on December 2, 2013, the liability for active union employees of New AER and its subsidiaries not eligible to retire was amendedtransferred to adjustIPH based on the calculationassumption of the future benefit obligation of approximately 430 labor union-represented employees fromcollective bargaining agreements in place, which resulted in a traditional, final pay formula to a cash balance formula.
settlement. See Note 16 – Divestiture Transactions and Discontinued Operations for further information on the divestiture. |
| |
| (e) | EEI implemented an employee reduction programIncluded in 2012, which resulted"Other assets" on Ameren's consolidated balance sheet. |
| |
| (f) | Included in a curtailment of EEI's pension and management postretirement benefit plans."Other current liabilities" on Ameren's consolidated balance sheet. |
The following table presents the assumptions used to determine our benefit obligations at December 31, 20122013, and 20112012:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2012 | | 2011 | | 2012 | | 2011 | 2013 | | 2012 | | 2013 | | 2012 |
| Discount rate at measurement date | 4.00 | % | | 4.50 | % | | 4.00 | % | | 4.50 | % | 4.75 | % | | 4.00 | % | | 4.75 | % | | 4.00 | % |
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
| Medical cost trend rate (initial) | — |
| | — |
| | 5.00 |
| | 5.50 |
| — |
| | — |
| | 5.00 |
| | 5.00 |
|
| Medical cost trend rate (ultimate) | — |
| | — |
| | 5.00 |
| | 5.00 |
| — |
| | — |
| | 5.00 |
| | 5.00 |
|
| Years to ultimate rate | 0 |
| | 0 |
| | 0 |
| | 1 year |
| — |
| | — |
| | — |
| | — |
|
Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan's projected benefit payments, pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations. The settlement portfolio of bonds is selected from a pool of over 600500 high-quality corporate bonds. A single discount rate is then determineddetermined; that rate results in a discounted value of the plan's benefit payments that equates to the market value of the selected bonds.
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’sits assumptions at December 31, 20122013, its investment performance in 2012,2013, and its pension funding policy, Ameren expects to make annual contributions of $6020 million to $150100 million in each of the next five years, with aggregate estimated contributions of $550270 million. We expect Ameren Missouri’s and Ameren Illinois’ portion of the future funding requirements to be 50%52%, and 40%47%, respectively. These amounts are estimates. The estimatesThey may change based on actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions. Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
The following table presents the cash contributions made to our defined benefit retirement plan and to our postretirement plans during 20122013, 20112012, and 20102011:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 |
| AMO | $ | 52 |
| | $ | 43 |
| | $ | 36 |
| | $ | 9 |
| | $ | 9 |
| | $ | 11 |
| |
| AIC | 46 |
| | 28 |
| | 23 |
| | 35 |
| | 118 |
| | 20 |
| |
| Ameren Missouri | | $ | 60 |
| | $ | 52 |
| | $ | 43 |
| | $ | 10 |
| | $ | 9 |
| | $ | 9 |
|
| Ameren Illinois | | 50 |
| | 46 |
| | 28 |
| | 11 |
| | 35 |
| | 118 |
|
| Other | 36 |
| | 32 |
| | 22 |
| | 1 |
| | 2 |
| | 5 |
| 46 |
| | 30 |
| | 25 |
| | 4 |
| | 1 |
| | 2 |
|
Ameren(a) | 134 |
| | 103 |
| | 81 |
| | 45 |
| | 129 |
| | 36 |
| 156 |
| | 128 |
| | 96 |
| | 25 |
| | 45 |
| | 129 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
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 includes 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 andpayable; 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 will utilizeuse an expected return on plan assets for its pension plan assets and postretirement plan assets of 7.50%7.25% and 7.25%7.00%, respectively, in 2013.2014. No plan assets are expected to be returned to Ameren during 2013.2014.
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 2013
2014 and our pension and postretirement plans’ asset categories as of December 31, 20122013, and 20112012.
| | Asset Category | Target Allocation 2013 | | Percentage of Plan Assets at December 31, | Target Allocation 2014 | | Percentage of Plan Assets at December 31, |
| 2012 | | 2011 | 2013 | | 2012 |
| Pension Plan: | | | | | | | | |
| Cash and cash equivalents | 0 - 5 % | | 2 | % | | 2 | % | 0 - 5 % | | 2 | % | | 2 | % |
| Equity securities: | | | | | | | | |
| U.S. large capitalization | 29 - 39 | | 34 |
| | 33 | % | 29 - 39 | | 36 |
| | 34 | % |
| U.S. small and mid-capitalization | 2 - 12 | | 7 |
| | 7 | % | 2 - 12 | | 8 |
| | 7 | % |
| International and emerging markets | 9 - 19 | | 13 |
| | 11 | % | 9 - 19 | | 14 |
| | 13 | % |
| Total equity | 50 - 60 | | 54 |
| | 51 | % | 50 - 60 | | 58 |
| | 54 | % |
| Debt securities | 35 - 45 | | 39 |
| | 42 | % | 35 - 45 | | 36 |
| | 39 | % |
| Real estate | 0 - 9 | | 4 |
| | 4 | % | 0 - 9 | | 4 |
| | 4 | % |
| Private equity | 0 - 4 | | 1 |
| | 1 | % | 0 - 4 | | (a) |
| | 1 | % |
| Total | | | 100 | % | | 100 | % | | | 100 | % | | 100 | % |
| Postretirement Plans: | | | | | | | | |
| Cash and cash equivalents | 0 - 10 % | | 4 | % | | 4 | % | 0 - 10 % | | 4 | % | | 4 | % |
| Equity securities: | | | | | | | | |
| U.S. large capitalization | 33 - 43 | | 40 | % | | 38 | % | 33 - 43 | | 41 | % | | 40 | % |
| U.S. small and mid-capitalization | 3 - 13 | | 8 | % | | 8 | % | 3 - 13 | | 8 | % | | 8 | % |
| International | 10 - 20 | | 14 | % | | 13 | % | 10 - 20 | | 14 | % | | 14 | % |
| Total equity | 55 - 65 | | 62 | % | | 59 | % | 55 - 65 | | 63 | % | | 62 | % |
| Debt securities | 30 - 40 | | 34 | % | | 37 | % | 30 - 40 | | 33 | % | | 34 | % |
| Total | | | 100 | % | | 100 | % | | | 100 | % | | 100 | % |
| |
(a) | Less than 1% of plan assets. |
In general, the United States large capitalization equity investments are passively managed or indexed, whereas the international, emerging markets, United States small capitalization, and United States 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-United States 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 109 different limited partnerships, with invested capital ranging from $0.1 million to $5 million each, which invest primarily in a diversified number of small United States-based companies. No further commitments may be made to private equity investments without approval by the finance committee of the board of directors. Additionally, Ameren’s investment committee allows investment managers to use derivatives, such as index futures, exchange traded funds, foreign exchange futures, and options, in certain situations, to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 20122013. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities traded in over-the-counter markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information. The fair value of real estate is based on annual appraisal reports prepared by an independent real estate appraiser.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 -– Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 20122013:
| | | | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total |
| Cash and cash equivalents | $ | 1 |
| | $ | 30 |
| | $ | — |
| | $ | 31 |
| $ | 5 |
| | $ | 39 |
| | $ | — |
| | $ | 44 |
|
| Equity securities: | | | | | | | | | | | | | | |
| U.S. large capitalization | 83 |
| | 1,028 |
| | — |
| | 1,111 |
| 107 |
| | 1,162 |
| | — |
| | 1,269 |
|
| U.S. small and mid-capitalization | 235 |
| | 12 |
| | — |
| | 247 |
| 273 |
| | — |
| | — |
| | 273 |
|
| International and emerging markets | 134 |
| | 306 |
| | — |
| | 440 |
| 143 |
| | 372 |
| | — |
| | 515 |
|
| Debt securities: | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 832 |
| | — |
| | 832 |
| — |
| | 860 |
| | — |
| | 860 |
|
| Municipal bonds | — |
| | 177 |
| | — |
| | 177 |
| — |
| | 149 |
| | — |
| | 149 |
|
| U.S. treasury and agency securities | — |
| | 250 |
| | — |
| | 250 |
| — |
| | 256 |
| | — |
| | 256 |
|
| Other | — |
| | 42 |
| | — |
| | 42 |
| — |
| | 27 |
| | — |
| | 27 |
|
| Real estate | — |
| | — |
| | 118 |
| | 118 |
| — |
| | — |
| | 131 |
| | 131 |
|
| Private equity | — |
| | — |
| | 19 |
| | 19 |
| — |
| | — |
| | 15 |
| | 15 |
|
| Derivative assets | — |
| | — |
| | — |
| | — |
| 1 |
| | — |
| | — |
| | 1 |
|
| Derivative liabilities | (1 | ) | | — |
| | — |
| | (1 | ) | (1 | ) | | — |
| | — |
| | (1 | ) |
| Total | $ | 452 |
| | $ | 2,677 |
| | $ | 137 |
| | $ | 3,266 |
| $ | 528 |
| | $ | 2,865 |
| | $ | 146 |
| | $ | 3,539 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | (102 | ) | | | | | | | (112 | ) |
Plus: Net receivables at December 31(b) | | | | | | | 29 |
| | | | | | | 34 |
|
| Fair value of pension plans assets at year end | | | | | | | $ | 3,193 |
| | | | | | | $ | 3,461 |
|
| |
| (a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation. |
| |
| (b) | Receivables related to pending security sales, offset by payables related to pending security purchases. |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 -– Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 20112012:
| | | | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total |
| Cash and cash equivalents | $ | — |
| | $ | 31 |
| | $ | — |
| | $ | 31 |
| $ | 1 |
| | $ | 28 |
| | $ | — |
| | $ | 29 |
|
| Equity securities: | | | | | | | | | | | | | | |
| U.S. large capitalization | 72 |
| | 922 |
| | — |
| | 994 |
| 83 |
| | 1,007 |
| | — |
| | 1,090 |
|
| U.S. small and mid-capitalization | 202 |
| | 11 |
| | — |
| | 213 |
| 235 |
| | — |
| | — |
| | 235 |
|
| International and emerging markets | 115 |
| | 213 |
| | — |
| | 328 |
| 134 |
| | 301 |
| | — |
| | 435 |
|
| Debt securities: | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 794 |
| | — |
| | 794 |
| — |
| | 832 |
| | — |
| | 832 |
|
| Municipal bonds | — |
| | 176 |
| | — |
| | 176 |
| — |
| | 176 |
| | — |
| | 176 |
|
| U.S. treasury and agency securities | — |
| | 230 |
| | — |
| | 230 |
| — |
| | 250 |
| | — |
| | 250 |
|
| Other | — |
| | 47 |
| | — |
| | 47 |
| — |
| | 17 |
| | — |
| | 17 |
|
| Real estate | — |
| | — |
| | 108 |
| | 108 |
| — |
| | — |
| | 118 |
| | 118 |
|
| Private equity | — |
| | — |
| | 23 |
| | 23 |
| — |
| | — |
| | 19 |
| | 19 |
|
| Derivative assets | 1 |
| | — |
| | — |
| | 1 |
| — |
| | — |
| | — |
| | — |
|
| Derivative liabilities | (1 | ) | | — |
| | — |
| | (1 | ) | (1 | ) | | — |
| | — |
| | (1 | ) |
| Total | $ | 389 |
| | $ | 2,424 |
| | $ | 131 |
| | $ | 2,944 |
| $ | 452 |
| | $ | 2,611 |
| | $ | 137 |
| | $ | 3,200 |
|
Less: Medical benefit assets at December 31(a) | | | | | | | (91 | ) | | | | | | | (102 | ) |
Plus: Net receivables at December 31(b) | | | | | | | 23 |
| | | | | | | 29 |
|
| Fair value of pension plans assets at year end | | | | | | | $ | 2,876 |
| | | | | | | $ | 3,127 |
|
| |
| (a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation. |
| |
| (b) | Receivables related to pending security sales, offset by payables related to pending security purchases. |
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 years ended December 31, 20122013, and 20112012:
| | | | Beginning Balance at January 1, | | Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date | | Actual Return on Plan Assets Related to Assets Sold During the Period | | Purchases, Sales, and Settlements, net | | Net Transfers into (out of) of Level 3 | | Ending Balance at December 31, | Beginning Balance at January 1, | | Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date | | Actual Return on Plan Assets Related to Assets Sold During the Period | | Purchases, Sales, and Settlements, Net | | Net Transfers into (out of) of Level 3 | | Ending Balance at December 31, |
| 2013: | | | | | | | | | | | | |
| Real estate | | $ | 118 |
| | $ | 9 |
| | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 131 |
|
| Private equity | | 19 |
| | (9 | ) | | 11 |
| | (6 | ) | | — |
| | 15 |
|
| 2012: | | | | | | | | | | | | | | | | | | | | | | |
| Real estate | $ | 108 |
| | $ | 7 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 118 |
| $ | 108 |
| | $ | 7 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 118 |
|
| Private equity | 23 |
| | (7 | ) | | 8 |
| | (5 | ) | | — |
| | 19 |
| 23 |
| | (7 | ) | | 8 |
| | (5 | ) | | — |
| | 19 |
|
| 2011: | | | | | | | | | | | | |
| Real estate | $ | 98 |
| | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 108 |
| |
| Private equity | 28 |
| | (10 | ) | | 11 |
| | (6 | ) | | — |
| | 23 |
| |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 -– Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 20122013:
| | | | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total |
| Cash and cash equivalents | $ | 83 |
| | $ | 1 |
| | $ | — |
| | $ | 84 |
| $ | 77 |
| | $ | — |
| | $ | — |
| | $ | 77 |
|
| Equity securities: | | | | | | | | | | | | | | |
| U.S. large capitalization | 277 |
| | 88 |
| | — |
| | 365 |
| 297 |
| | 101 |
| | — |
| | 398 |
|
| U.S. small and mid-capitalization | 66 |
| | — |
| | — |
| | 66 |
| 77 |
| | — |
| | — |
| | 77 |
|
| International | 51 |
| | 69 |
| | — |
| | 120 |
| 39 |
| | 96 |
| | — |
| | 135 |
|
| Debt securities: | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 94 |
| | — |
| | 94 |
| — |
| | 89 |
| | — |
| | 89 |
|
| Municipal bonds | — |
| | 97 |
| | — |
| | 97 |
| — |
| | 103 |
| | — |
| | 103 |
|
| U.S. treasury and agency securities | — |
| | 78 |
| | — |
| | 78 |
| — |
| | 72 |
| | — |
| | 72 |
|
| Asset-backed securities | — |
| | 18 |
| | — |
| | 18 |
| — |
| | 10 |
| | — |
| | 10 |
|
| Other | — |
| | 22 |
| | — |
| | 22 |
| — |
| | 40 |
| | — |
| | 40 |
|
| Total | $ | 477 |
| | $ | 467 |
| | $ | — |
| | $ | 944 |
| $ | 490 |
| | $ | 511 |
| | $ | — |
| | $ | 1,001 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | 102 |
| | | | | | | 112 |
|
Less: Net payables at December 31(b) | | | | | | | (46 | ) | | | | | | | (39 | ) |
| Fair value of postretirement benefit plans assets at year end | | | | | | | $ | 1,000 |
| | | | | | | $ | 1,074 |
|
| |
| (a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
| |
| (b) | Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales. |
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 -– Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 20112012:
| | | | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total | Quoted Prices in Active Markets for Identified Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Other Unobservable Inputs (Level 3) | | Total |
| Cash and cash equivalents | $ | 1 |
| | $ | 66 |
| | $ | — |
| | $ | 67 |
| $ | 83 |
| | $ | — |
| | $ | — |
| | $ | 83 |
|
| Equity securities: | | | | | | | | | | | | | | |
| U.S. large capitalization | 235 |
| | 78 |
| | — |
| | 313 |
| 245 |
| | 88 |
| | — |
| | 333 |
|
| U.S. small and mid-capitalization | 57 |
| | — |
| | — |
| | 57 |
| 66 |
| | — |
| | — |
| | 66 |
|
| International | 44 |
| | 56 |
| | — |
| | 100 |
| 45 |
| | 69 |
| | — |
| | 114 |
|
| Debt securities: | | | | | | | | | | | | | | |
| Corporate bonds | — |
| | 75 |
| | — |
| | 75 |
| — |
| | 88 |
| | — |
| | 88 |
|
| Municipal bonds | — |
| | 86 |
| | — |
| | 86 |
| — |
| | 91 |
| | — |
| | 91 |
|
| U.S. treasury and agency securities | — |
| | 82 |
| | — |
| | 82 |
| — |
| | 67 |
| | — |
| | 67 |
|
| Asset-backed securities | — |
| | 23 |
| | — |
| | 23 |
| — |
| | 18 |
| | — |
| | 18 |
|
| Other | — |
| | 35 |
| | — |
| | 35 |
| — |
| | 22 |
| | — |
| | 22 |
|
| Total | $ | 337 |
| | $ | 501 |
| | $ | — |
| | $ | 838 |
| $ | 439 |
| | $ | 443 |
| | $ | — |
| | $ | 882 |
|
Plus: Medical benefit assets at December 31(a) | | | | | | | 91 |
| | | | | | | 102 |
|
Less: Net payables at December 31(b) | | | | | | | (33 | ) | | | | | | | (46 | ) |
| Fair value of postretirement benefit plans assets at year end | | | | | | | $ | 896 |
| | | | | | | $ | 938 |
|
| |
| (a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
| |
| (b) | Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales. |
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit plans during 20122013, 20112012, and 20102011:
| | | | Pension Benefits Ameren(a) | | Postretirement Benefits Ameren(a) | Pension Benefits Ameren(a) | | Postretirement Benefits Ameren(a) |
| 2013 | | | | |
| Service cost | | $ | 91 |
| | $ | 22 |
|
| Interest cost | | 163 |
| | 46 |
|
| Expected return on plan assets | | (218 | ) | | (62 | ) |
| Amortization of: | | | | |
| Transition obligation | | — |
| | — |
|
| Prior service cost | | (2 | ) | | (6 | ) |
| Actuarial loss | | 87 |
| | 8 |
|
| Curtailment gain | | (12 | ) | | (7 | ) |
Net periodic benefit cost(b) | | $ | 109 |
| | $ | 1 |
|
| 2012 | | | | | | |
| Service cost | $ | 83 |
| | $ | 24 |
| $ | 81 |
| | $ | 22 |
|
| Interest cost | 170 |
| | 52 |
| 166 |
| | 47 |
|
| Expected return on plan assets | (213 | ) | | (60 | ) | (208 | ) | | (56 | ) |
| Amortization of: | | | | | | |
| Transition obligation | — |
| | 2 |
| — |
| | 2 |
|
| Prior service cost | (3 | ) | | (8 | ) | (3 | ) | | (6 | ) |
| Actuarial loss | 77 |
| | 9 |
| 75 |
| | 5 |
|
Curtailment loss(b) | 2 |
| | — |
| |
| Net periodic benefit cost | $ | 116 |
| | $ | 19 |
| |
Net periodic benefit cost | | $ | 111 |
| | $ | 14 |
|
| 2011 | | | | | | |
| Service cost | $ | 75 |
| | $ | 22 |
| $ | 73 |
| | $ | 20 |
|
| Interest cost | 180 |
| | 58 |
| 175 |
| | 54 |
|
| Expected return on plan assets | (216 | ) | | (54 | ) | (211 | ) | | (50 | ) |
| Amortization of: | | | | | | |
| Transition obligation | — |
| | 2 |
| — |
| | 2 |
|
| Prior service cost | (1 | ) | | (8 | ) | (1 | ) | | (6 | ) |
| Actuarial loss | 42 |
| | 5 |
| 41 |
| | 3 |
|
Net periodic benefit cost | $ | 80 |
| | $ | 25 |
| $ | 77 |
| | $ | 23 |
|
| 2010 | | | | |
| Service cost | $ | 68 |
| | $ | 20 |
| |
| Interest cost | 185 |
| | 62 |
| |
| Expected return on plan assets | (212 | ) | | (56 | ) | |
| Amortization of: | | | | |
| Transition obligation | — |
| | 2 |
| |
| Prior service cost | 6 |
| | (8 | ) | |
| Actuarial loss | 18 |
| | 1 |
| |
| Net periodic benefit cost | $ | 65 |
| | $ | 21 |
| |
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
| (b) | Includes EEI'sThe net periodic benefit cost includes a $6 million and a $7 million net gain for pension benefits and management postretirement benefit plans'benefits, respectively, which was included in "Income (loss) from discontinued operations, net of taxes" on Ameren's consolidated statement of income (loss). This net gain includes the curtailment loss of $2 milliongain recognized in 20122013 as a result of its employeea significant reduction program.
in employees as of the December 2, 2013 closing date of the New AER divestiture. See Note 16 – Divestiture Transactions and Discontinued Operations for additional information on the divestiture. |
| |
| (c) | The net periodic benefit cost includes $9 million and $- million in total net costs for pension benefits and postretirement benefits, respectively, for 2012 which were included in "Income (loss) from discontinued operations, net of taxes" on Ameren's consolidated statement of income (loss). The net periodic benefit cost includes $7 million and $- million in total net costs for pension benefits and postretirement benefits, respectively, for 2011 which were included in "Income (loss) from discontinued operations, net of taxes" on Ameren's consolidated statement of income (loss). See Note 16 – Divestiture Transactions and Discontinued Operations for additional information on the divestiture. |
The current year expected return on plan assets is determined primarily 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 20132014 are as follows:
| | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| Ameren(a) | | Ameren(a) | Ameren(a) | | Ameren(a) |
| Regulatory assets: | | | | | | |
| Prior service cost (credit) | $ | (1 | ) | | $ | (4 | ) | $ | (1 | ) | | $ | (4 | ) |
| Net actuarial loss | 97 |
| | 19 |
| 60 |
| | 9 |
|
| Accumulated OCI: | | | | | | |
| Prior service cost (credit) | (2 | ) | | (9 | ) | |
| Net actuarial loss | 7 |
| | 5 |
| |
| Net actuarial (gain) loss | | 1 |
| | (2 | ) |
| Total | $ | 101 |
| | $ | 11 |
| $ | 60 |
| | $ | 3 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. The net actuarial (gain) loss subject to amortization is amortized on a straight-line basis over 10 years.
The Ameren Companies are responsible for their share of the pension and postretirement benefit costs. The following table presents the pension costs and the postretirement benefit costs incurred and included in continuing operations for the years ended December 31, 2013, 2012, 2011, and 2010:2011:
| | | | Pension Costs | | Postretirement Costs | Pension Costs | | Postretirement Costs |
| | 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 |
| Ameren Missouri | $ | 63 |
| | $ | 51 |
| | $ | 42 |
| | $ | 10 |
| | $ | 11 |
| | $ | 11 |
| $ | 69 |
| | $ | 63 |
| | $ | 51 |
| | $ | 8 |
| | $ | 10 |
| | $ | 11 |
|
| Ameren Illinois | 37 |
| | 16 |
| | 10 |
| | 4 |
| | 11 |
| | 7 |
| 41 |
| | 37 |
| | 16 |
| | — |
| | 4 |
| | 11 |
|
Other (b) | 16 |
| | 13 |
| | 13 |
| | 5 |
| | 3 |
| | 3 |
| 5 |
| | 2 |
| | 3 |
| | — |
| | — |
| | 1 |
|
Ameren(b)(a) | 116 |
| | 80 |
| | 65 |
| | 19 |
| | 25 |
| | 21 |
| 115 |
| | 102 |
| | 70 |
| | 8 |
| | 14 |
| | 23 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
(b) | Includes EEI's pension and management postretirement benefit plans' curtailment loss of $2 million recognized in 2012 as a result of its employee reduction program.
|
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, 20122013, are as follows:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | Paid from Qualified Trust | | Paid from Company Funds | | Paid from Qualified Trust | | Paid from Company Funds | | Federal Subsidy | Paid from Qualified Trust | | Paid from Company Funds | | Paid from Qualified Trust | | Paid from Company Funds | | Federal Subsidy |
| 2013 | $ | 235 |
| | $ | 3 |
| | $ | 60 |
| | $ | 2 |
| | $ | 3 |
| |
| 2014 | 243 |
| | 3 |
| | 62 |
| | 2 |
| | 3 |
| $ | 247 |
| | $ | 3 |
| | $ | 61 |
| | $ | 2 |
| | $ | 3 |
|
| 2015 | 247 |
| | 3 |
| | 65 |
| | 2 |
| | 3 |
| 249 |
| | 3 |
| | 63 |
| | 2 |
| | 4 |
|
| 2016 | 253 |
| | 3 |
| | 68 |
| | 2 |
| | 4 |
| 255 |
| | 3 |
| | 66 |
| | 2 |
| | 4 |
|
| 2017 | 255 |
| | 3 |
| | 71 |
| | 2 |
| | 4 |
| 260 |
| | 3 |
| | 69 |
| | 2 |
| | 4 |
|
| 2018 - 2022 | 1,317 |
| | 13 |
| | 398 |
| | 11 |
| | 19 |
| |
| 2018 | | 264 |
| | 3 |
| | 72 |
| | 2 |
| | 4 |
|
| 2019 - 2023 | | 1,342 |
| | 14 |
| | 394 |
| | 12 |
| | 19 |
|
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, 2013, 2012, 2011, and 2010:2011:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 | | 2013 | | 2012 | | 2011 |
| Discount rate at measurement date | 4.50 | % | | 5.25 | % | | 5.75 | % | | 4.50 | % | | 5.25 | % | | 5.75 | % | 4.00 | % | | 4.50 | % | | 5.25 | % | | 4.00 | % | | 4.50 | % | | 5.25 | % |
| Expected return on plan assets | 7.75 |
| | 8.00 |
| | 8.00 |
| | 7.50 |
| | 7.75 |
| | 8.00 |
| 7.50 |
| | 7.75 |
| | 8.00 |
| | 7.25 |
| | 7.50 |
| | 7.75 |
|
| Increase in future compensation | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
| | 3.50 |
|
| Medical cost trend rate (initial) | — |
| | — |
| | — |
| | 5.50 |
| | 6.00 |
| | 6.50 |
| — |
| | — |
| | — |
| | 5.00 |
| | 5.50 |
| | 6.00 |
|
| Medical cost trend rate (ultimate) | — |
| | — |
| | — |
| | 5.00 |
| | 5.00 |
| | 5.00 |
| — |
| | — |
| | — |
| | 5.00 |
| | 5.00 |
| | 5.00 |
|
| Years to ultimate rate | 0 |
| | 0 |
| | 0 |
| | 1 year |
| | 2 years |
| | 3 years |
| — |
| | — |
| | — |
| | — |
| | 1 year |
| | 2 years |
|
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
| | | | Pension Benefits | | Postretirement Benefits | Pension Benefits | | Postretirement Benefits |
| | Service Cost and Interest Cost | | Projected Benefit Obligation | | Service Cost and Interest Cost | | Postretirement Benefit Obligation | Service Cost and Interest Cost | | Projected Benefit Obligation | | Service Cost and Interest Cost | | Postretirement Benefit Obligation |
| 0.25% decrease in discount rate | $ | (2 | ) | | $ | 124 |
| | $ | — |
| | $ | 36 |
| $ | (2 | ) | | $ | 109 |
| | $ | — |
| | $ | 32 |
|
| 0.25% increase in salary scale | 2 |
| | 13 |
| | — |
| | — |
| 2 |
| | 17 |
| | — |
| | — |
|
| 1.00% increase in annual medical trend | — |
| | — |
| | 1 |
| | 40 |
| — |
| | — |
| | 2 |
| | 40 |
|
| 1.00% decrease in annual medical trend | — |
| | — |
| | — |
| | (38 | ) | — |
| | — |
| | (2 | ) | | (37 | ) |
Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees at December 31, 20122013. The plan allowed employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matched a percentage of the employee contributions up to certain limits. The following table presents the portion of the matching contribution to the Ameren 401(k) plan attributable to the continuing operations for each of the Ameren Companies for the years ended December 31, 20122013, 20112012, and 20102011:
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Ameren Missouri | $ | 16 |
| | $ | 16 |
| | $ | 16 |
| $ | 16 |
| | $ | 16 |
| | $ | 16 |
|
| Ameren Illinois | 9 |
| | 8 |
| | 8 |
| 10 |
| | 9 |
| | 8 |
|
| Other | 4 |
| | 4 |
| | 3 |
| 1 |
| | 1 |
| | 1 |
|
Ameren(a) | 29 |
| | 28 |
| | 27 |
| 27 |
| | 26 |
| | 25 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
NOTE 12 -– STOCK-BASED COMPENSATION
Ameren’s long-term incentive plan is available to for eligible employees under Ameren'sis the shareholder-approved 2006 Omnibus Incentive Compensation Plan (2006 Plan), which became 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. 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 at December 31, 20122013, and changes during the year ended December 31, 20122013, under the 2006 Plan are presented below:
| | | | Performance Share Units | Performance Share Units |
| | Share Units | | Weighted-average Fair Value per Unit | Share Units | | Weighted-average Fair Value per Unit |
| Nonvested at January 1, 2012 | 1,156,831 |
| | $ | 31.70 |
| |
| Nonvested at January 1, 2013 | | 1,192,487 |
| | $ | 33.56 |
|
Granted(a) | 717,151 |
| | 35.68 |
| 840,482 |
| | 31.19 |
|
Unearned or forfeited(b) | (477,928 | ) | | 32.04 |
| (29,730 | ) | | 31.93 |
|
Earned and vested(c) | (203,567 | ) | | 34.01 |
| (784,695 | ) | | 31.60 |
|
| Nonvested at December 31, 2012 | 1,192,487 |
| | $ | 33.56 |
| |
| Nonvested at December 31, 2013 | | 1,218,544 |
| | $ | 33.23 |
|
| |
| (a) | Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 20122013 under the 2006 Plan. |
| |
| (b) | Includes share units granted in 20102011 that were not earned based on performance provisions of the award grants. |
| |
| (c) | Includes share units granted in 20102011 that vested as of December 31, 20122013, that were earned pursuant to the provisions of the award grants. Also includes share units that vested due to attainment of retirement eligibility by certain employees.employees and certain employees whose employment terminated on December 2, 2013, with the divestiture of New AER. Actual shares issued for retirement-eligible employees and former New AER subsidiaries' employees will vary depending on actual performance over the three-year measurement period. |
Ameren recorded compensation expense of $2420 million, $1422 million, and $13 million for the years ended December 31, 20122013, 20112012, and 20102011, respectively, and a related tax benefit of $98 million, $58 million and $5 million for the years ended December 31, 20122013, 20112012, and 20102011, respectively. Ameren settled performance share units and restricted shares of $11 million, $411 million, and $24 million for the years ended December 31, 20122013, 20112012, and 20102011. All outstanding restricted shares vested as of the end of 2011. There were no significant compensation costs capitalized related to the performance share units during the years ended December 31, 20122013, 20112012, and 20102011. As of December 31, 20122013, total compensation cost of $2120 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 20 months.
Performance Share Units
Performance share units have been granted under the 2006 Plan. A share unit vests and entitles 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 varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.
The fair value of each share unit awarded in January 2013 under the 2006 Plan was determined to be $31.19. That amount
was based on Ameren's closing common share price of $30.72 at December 31, 2012, 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, 2013. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.36%, volatility of 12% to 21% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.
The fair value of each share unit awarded in January 2012 under the 2006 Plan was determined to be $35.68. That amount
was based on Ameren'sAmeren’s closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren'sAmeren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren'sAmeren’s attainment of a three-year average earnings per share threshold during the performance period.
The fair value of each share unit awarded in January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren’s closing common share price of $28.19 at December 31, 2010, 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, 2011. The simulations can produce a greater fair value for the share unit than the closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren’s attainment of three-year average earnings per share threshold during the performance period.
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, 20122013, 20112012, and 20102011:
| | | | Ameren | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois | | Ameren |
| 2013 | | | | | | |
| Statutory federal income tax rate: | | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | | |
| Depreciation differences | | — |
| | (1 | ) | | — |
|
| Amortization of investment tax credit | | (1 | ) | | — |
| | (1 | ) |
| State tax | | 3 |
| | 6 |
| | 4 |
|
Other permanent items(a) | | 1 |
| | — |
| | — |
|
| Effective income tax rate | | 38 | % | | 40 | % | | 38 | % |
| 2012 | | | | | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | | | | | | |
| Depreciation differences | — |
| | (1 | ) | | — |
| (1 | ) | | — |
| | (1 | ) |
| Amortization of investment tax credit | 1 |
| | (1 | ) | | (1 | ) | (1 | ) | | (1 | ) | | (1 | ) |
| State tax | 5 |
| | 3 |
| | 6 |
| 3 |
| | 6 |
| | 5 |
|
| Reserve for uncertain tax positions | — |
| | 1 |
| | — |
| 1 |
| | — |
| | — |
|
Other permanent items(a) | | — |
| | — |
| | (1 | ) |
| Effective income tax rate | 41 | % | | 37 | % | | 40 | % | 37 | % | | 40 | % | | 37 | % |
| 2011 | | | | | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | 35 | % | | 35 | % | | 35 | % |
| Increases (decreases) from: | | | | | | | | | | |
| Depreciation differences | (1 | ) | | (2 | ) | | — |
| (2 | ) | | — |
| | (1 | ) |
| Amortization of investment tax credit | (1 | ) | | (1 | ) | | (1 | ) | (1 | ) | | (1 | ) | | (1 | ) |
| State tax | 4 |
| | 3 |
| | 5 |
| 3 |
| | 5 |
| | 4 |
|
| Reserve for uncertain tax positions | | — |
| | — |
| | 1 |
|
| Tax credits | | — |
| | — |
| | (1 | ) |
Other permanent items(a) | — |
| | 1 |
| | — |
| 1 |
| | — |
| | — |
|
| Effective income tax rate | 37 | % | | 36 | % | | 39 | % | 36 | % | | 39 | % | | 37 | % |
| 2010 | | | | | | |
| Statutory federal income tax rate: | 35 | % | | 35 | % | | 35 | % | |
| Increases (decreases) from: | | | | | | |
| Non-deductible impairment of goodwill | 32 |
| | — |
| | — |
| |
| Depreciation differences | (4 | ) | | (3 | ) | | — |
| |
| Amortization of investment tax credit | (2 | ) | | (1 | ) | | (1 | ) | |
| State tax | 8 |
| | 3 |
| | 5 |
| |
| Reserve for uncertain tax positions | (1 | ) | | — |
| | — |
| |
| Tax credits | (3 | ) | | — |
| | — |
| |
Change in federal tax law(b) | 3 |
| | 1 |
| | — |
| |
| Effective income tax rate | 68 | % | | 35 | % | | 39 | % | |
| |
| (a) | Permanent items are treated differently for book and tax purposes and primarily include non-taxable income related to company-owned life insurance and deductions related to dividends on DRPlus and the 401(k) plan for Ameren, as well as nondeductible expenses related to lobbying and stock issuance expensescosts for Ameren Missouri. |
| |
(b) | Relates to change in taxation of prescription drug benefits to retiree participants from the enactment in 2010 of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010. |
The following table presents the components of income tax expense (benefit) for the years ended December 31, 20122013, 20112012, and 20102011:
| | | | Ameren(a) | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois | | Other | | Ameren(a) |
| 2013 | | | | | | | | |
| Current taxes: | | | | | | | | |
| Federal | | $ | 136 |
| | $ | (15 | ) | | $ | (239 | ) | (b) | $ | (118 | ) |
| State | | 41 |
| | 21 |
| | (43 | ) | (b) | 19 |
|
| Deferred taxes: | | | | | | | | |
| Federal | | 64 |
| | 99 |
| | 205 |
| (b) | 368 |
|
| State | | 6 |
| | 6 |
| | 36 |
| (b) | 48 |
|
| Deferred investment tax credits, amortization | | (5 | ) | | (1 | ) | | — |
| | (6 | ) |
| Total income tax expense (benefit) | | $ | 242 |
| | $ | 110 |
| | $ | (41 | ) | | $ | 311 |
|
| 2012 | | | | | | | | | | | | |
| Current taxes: | | | | | | | | | | | | |
| Federal | $ | 31 |
| | $ | (25 | ) | | $ | (7 | ) | $ | (25 | ) | | $ | (7 | ) | | $ | 72 |
| | $ | 40 |
|
| State | 3 |
| | (10 | ) | | (3 | ) | (10 | ) | | (3 | ) | | 23 |
| | 10 |
|
| Deferred taxes: | | | | | | | | | | | | |
| Federal | (590 | ) | | 248 |
| | 76 |
| 248 |
| | 76 |
| | (120 | ) | | 204 |
|
| State | (117 | ) | | 44 |
| | 30 |
| 44 |
| | 30 |
| | (14 | ) | | 60 |
|
| Deferred investment tax credits, amortization | (7 | ) | | (5 | ) | | (2 | ) | (5 | ) | | (2 | ) | | — |
| | (7 | ) |
| Total income tax expense (benefit) | $ | (680 | ) | | $ | 252 |
| | $ | 94 |
| $ | 252 |
| | $ | 94 |
| | $ | (39 | ) | | $ | 307 |
|
| 2011 | | | | | | | | | | | | |
| Current taxes: | | | | | | | | | | | | |
| Federal | $ | (27 | ) | | $ | 3 |
| | $ | (24 | ) | $ | 3 |
| | $ | (24 | ) | | $ | 15 |
| | $ | (6 | ) |
| State | (5 | ) | | 2 |
| | (4 | ) | 2 |
| | (4 | ) | | — |
| | (2 | ) |
| Deferred taxes: | | | | | | | | | | | | |
| Federal | 273 |
| | 129 |
| | 123 |
| 129 |
| | 123 |
| | (39 | ) | | 213 |
|
| State | 76 |
| | 31 |
| | 34 |
| 31 |
| | 34 |
| | (10 | ) | | 55 |
|
| Deferred investment tax credits, amortization | (7 | ) | | (4 | ) | | (2 | ) | (4 | ) | | (2 | ) | | — |
| | (6 | ) |
| Total income tax expense | $ | 310 |
| | $ | 161 |
| | $ | 127 |
| |
| 2010 | | | | | | |
| Current taxes: | | | | | | |
| Federal | $ | 13 |
| | $ | (14 | ) | | $ | (20 | ) | |
| State | 10 |
| | (15 | ) | | (5 | ) | |
| Deferred taxes: | | | | | | |
| Federal | 274 |
| | 206 |
| | 132 |
| |
| State | 36 |
| | 27 |
| | 32 |
| |
| Deferred investment tax credits, amortization | (8 | ) | | (5 | ) | | (2 | ) | |
| Total income tax expense | $ | 325 |
| | $ | 199 |
| | $ | 137 |
| |
| Total income tax expense (benefit) | | $ | 161 |
| | $ | 127 |
| | $ | (34 | ) | | $ | 254 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | These amounts are substantially related to the reversal of unrecognized tax benefits as a result of new IRS guidance related to the deductibility of expenditures to maintain, replace or improve steam or electric power generation property, along with casualty loss deductions for storm damage. They also reflect the increase in deferred tax expense due to available net operating losses. |
The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting inas of January 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 increased current income tax expense in 2011 by $6 million and $4 million for Ameren and Ameren Illinois, respectively. As a result of this corporate income tax rate increase, accumulated deferred tax balances were revalued, resulting in a decrease in deferred tax expense of $2 million and $3 million for Ameren and Ameren Illinois, respectively, in 2011.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 20122013, and 20112012:
| | | | Ameren(a) | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois | | Other | | Ameren(a) |
| 2013 | | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | | |
| Plant related | | $ | 2,513 |
| | $ | 1,243 |
| | $ | 13 |
| | $ | 3,769 |
|
| Regulatory assets, net | | 74 |
| | 2 |
| | — |
| | 76 |
|
| Deferred employee benefit costs | | (74 | ) | | (85 | ) | | (114 | ) | | (273 | ) |
| Purchase accounting | | — |
| | (27 | ) | | (1 | ) | | (28 | ) |
| ARO | | (7 | ) | | 1 |
| | — |
| | (6 | ) |
Other(b)(c) | | (17 | ) | | (63 | ) | | (398 | ) | | (478 | ) |
Total net accumulated deferred income tax liabilities (assets)(d) | | $ | 2,489 |
| | $ | 1,071 |
| | $ | (500 | ) | | $ | 3,060 |
|
| 2012 | | | | | | | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | | | | | | | |
| Plant related | $ | 4,201 |
| | $ | 2,386 |
| | $ | 1,106 |
| $ | 2,385 |
| | $ | 1,145 |
| | $ | 20 |
| | $ | 3,550 |
|
| Long-lived asset impairments | (986 | ) | | — |
| | — |
| |
| Deferred intercompany tax gain/basis step-up | 2 |
| | (1 | ) | | 39 |
| |
| Regulatory assets, net | 73 |
| | 73 |
| | — |
| 73 |
| | — |
| | — |
| | 73 |
|
| Deferred employee benefit costs | (337 | ) | | (84 | ) | | (102 | ) | (84 | ) | | (102 | ) | | (137 | ) | | (323 | ) |
| Purchase accounting | (10 | ) | | — |
| | (27 | ) | — |
| | (27 | ) | | (1 | ) | | (28 | ) |
| ARO | (44 | ) | | (7 | ) | | 1 |
| (7 | ) | | 1 |
| | — |
| | (6 | ) |
Other(b) | (278 | ) | | 50 |
| | (77 | ) | 50 |
| | (77 | ) | | (223 | ) | | (250 | ) |
Total net accumulated deferred income tax liabilities(c) | $ | 2,621 |
| | $ | 2,417 |
| | $ | 940 |
| |
| 2011 | | | | | | |
| Accumulated deferred income taxes, net liability (asset): | | | | | | |
| Plant related | $ | 3,826 |
| | $ | 2,134 |
| | $ | 1,003 |
| |
| Long-lived asset impairments | (15 | ) | | — |
| | — |
| |
| Deferred intercompany tax gain/basis step-up | 3 |
| | (1 | ) | | 55 |
| |
| Regulatory assets, net | 73 |
| | 73 |
| | — |
| |
| Deferred employee benefit costs | (367 | ) | | (88 | ) | | (109 | ) | |
| Purchase accounting | 35 |
| | — |
| | (27 | ) | |
| ARO | (37 | ) | | — |
| | 1 |
| |
| Other | (223 | ) | | 6 |
| | (86 | ) | |
Total net accumulated deferred income tax liabilities(d) | $ | 3,295 |
| | $ | 2,124 |
| | $ | 837 |
| |
Total net accumulated deferred income tax liabilities (assets)(e) | | $ | 2,417 |
| | $ | 940 |
| | $ | (341 | ) | | $ | 3,016 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below. |
| |
| (c) | Includes total valuation allowances for Ameren, Ameren Missouri, and Ameren Illinois of $7 million, $1 million, and $1 million, respectively, as of December 31, 2013. The state valuation allowances are shown in the table below. |
| |
| (d) | Includes $20 million recorded in "Other current assets" on Ameren Missouri's balance sheet as of December 31, 2013. |
| |
| (e) | Includes $26 million recorded in "Other current assets" on Ameren Missouri's balance sheet as of December 31, 2012.2012. |
The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2013:
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren(a) |
| Net operating loss carryforwards: | | | | | | | |
Federal(b) | $ | 61 |
| | $ | 84 |
| | $ | 215 |
| | $ | 360 |
|
State(c) | 3 |
| | 11 |
| | 34 |
| | 48 |
|
| Total net operating loss carryforwards | $ | 64 |
| | $ | 95 |
| | $ | 249 |
| | $ | 408 |
|
| Tax credit carryforwards: | | | | | | | |
Federal(d) | $ | 12 |
| | $ | — |
| | $ | 76 |
| | $ | 88 |
|
State(e) | 1 |
| | 1 |
| | 32 |
| | 34 |
|
State valuation allowance(f) | (1 | ) | | (1 | ) | | (2 | ) | | (4 | ) |
| Total tax credit carryforwards | $ | 12 |
| | $ | — |
| | $ | 106 |
| | $ | 118 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
| (b) | These will begin to expire in 2028. |
| |
| (c) | These will begin to expire in 2017. |
| |
| (d) | IncludesThese will begin to expire in $8 million2029 recorded in "Other current assets" on Ameren Missouri's balance sheet as of December 31, 2011..
|
| |
| (e) | These will begin to expire in 2014. |
| |
| (f) | This balance increased by $2 million, $- million and $- million for Ameren, Ameren Missouri and Ameren Illinois, respectively, during 2013. |
The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2012:
| | | | Ameren | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois | | Other | | Ameren(a) |
| Net operating loss carryforwards: | | | | | | | | | | | | |
Federal(a)(b) | $ | 212 |
| | $ | 61 |
| | $ | 61 |
| $ | 61 |
| | $ | 61 |
| | $ | 51 |
| | $ | 173 |
|
State(b)(c) | 29 |
| | 3 |
| | 11 |
| 3 |
| | 11 |
| | 13 |
| | 27 |
|
| Total net operating loss carryforwards | $ | 241 |
| | $ | 64 |
| | $ | 72 |
| $ | 64 |
| | $ | 72 |
| | $ | 64 |
| | $ | 200 |
|
| Tax credit carryforwards: | | | | | | | | | | | | |
Federal(c)(d) | $ | 87 |
| | $ | 11 |
| | $ | — |
| $ | 11 |
| | $ | — |
| | $ | 75 |
| | $ | 86 |
|
State(d)(e) | 35 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 23 |
| | 25 |
|
State valuation allowance(e)(f) | (4 | ) | | (1 | ) | | (1 | ) | (1 | ) | | (1 | ) | | — |
| | (2 | ) |
| Total tax credit carryforwards | $ | 118 |
| | $ | 11 |
| | $ | — |
| $ | 11 |
| | $ | — |
| | $ | 98 |
| | $ | 109 |
|
| |
| (a) | These will begin to expire in 2028.
Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
| (b) | These will begin to expire in 2017.2028 |
| |
| (c) | These will begin to expire in 2029. in2017. |
| |
| (d) | These will begin to expire in 2013. 2029. |
| |
| (e) | These began to expire in 2013. |
| |
| (f) | This balance increased by $21 million, $- million and $1$1 million for Ameren, Ameren Missouri and Ameren Illinois, respectively, during 2012. |
Uncertain Tax Positions
A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 20102011, 20112012, and 20122013, is as follows:
| | | | Ameren | | Ameren Missouri | | Ameren Illinois | Ameren Missouri | | Ameren Illinois | | Other | | Ameren(a) |
| Unrecognized tax benefits - January 1, 2010 | $ | 135 |
| | $ | 88 |
| | $ | — |
| |
| Increases based on tax positions prior to 2010 | 72 |
| | 40 |
| | 27 |
| |
| Decreases based on tax positions prior to 2010 | (38 | ) | | (12 | ) | | (2 | ) | |
| Increases based on tax positions related to 2010 | 77 |
| | 48 |
| | 31 |
| |
| Changes related to settlements with taxing authorities | — |
| | — |
| | — |
| |
| Decreases related to the lapse of statute of limitations | — |
| | — |
| | — |
| |
| Unrecognized tax benefits - December 31, 2010 | $ | 246 |
| | $ | 164 |
| | $ | 56 |
| |
| Unrecognized tax benefits – January 1, 2011 | | $ | 164 |
| | $ | 56 |
| | $ | 26 |
| | $ | 246 |
|
| Increases based on tax positions prior to 2011 | 22 |
| | 15 |
| | — |
| 15 |
| | — |
| | 7 |
| | 22 |
|
| Decreases based on tax positions prior to 2011 | (125 | ) | | (63 | ) | | (41 | ) | (63 | ) | | (41 | ) | | (21 | ) | | (125 | ) |
| Increases based on tax positions related to 2011 | 17 |
| | 13 |
| | — |
| 13 |
| | — |
| | 4 |
| | 17 |
|
| Changes related to settlements with taxing authorities | (10 | ) | | (5 | ) | | (4 | ) | (5 | ) | | (4 | ) | | (1 | ) | | (10 | ) |
| Decreases related to the lapse of statute of limitations | (2 | ) | | — |
| | — |
| — |
| | — |
| | (2 | ) | | (2 | ) |
| Unrecognized tax benefits - December 31, 2011 | $ | 148 |
| | $ | 124 |
| | $ | 11 |
| |
| Unrecognized tax benefits – December 31, 2011 | | $ | 124 |
| | $ | 11 |
| | $ | 13 |
| | $ | 148 |
|
| Increases based on tax positions prior to 2012 | 5 |
| | 4 |
| | — |
| 4 |
| | — |
| | 1 |
| | 5 |
|
| Decreases based on tax positions prior to 2012 | (13 | ) | | (7 | ) | | (1 | ) | (7 | ) | | (1 | ) | | (5 | ) | | (13 | ) |
| Increases based on tax positions related to 2012 | 17 |
| | 15 |
| | 3 |
| |
| Increases (decreases) based on tax positions related to 2012 | | 15 |
| | 3 |
| | (1 | ) | | 17 |
|
| Changes related to settlements with taxing authorities | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
|
| Decreases related to the lapse of statute of limitations | (1 | ) | | — |
| | — |
| — |
| | — |
| | (1 | ) | | (1 | ) |
| Unrecognized tax benefits - December 31, 2012 | $ | 156 |
| | $ | 136 |
| | $ | 13 |
| |
| Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of December 31, 2010 | $ | — |
| | $ | 3 |
| | $ | — |
| |
| Unrecognized tax benefits – December 31, 2012 | | $ | 136 |
| | $ | 13 |
| | $ | 7 |
| | $ | 156 |
|
| Increases based on tax positions prior to 2013 | | — |
| | 2 |
| | 5 |
| | 7 |
|
| Decreases based on tax positions prior to 2013 | | (122 | ) | | (16 | ) | | (5 | ) | | (143 | ) |
| Increases based on tax positions related to 2013 | | 16 |
| | — |
| | 53 |
| (b) | 69 |
|
| Changes related to settlements with taxing authorities | | — |
| | — |
| | — |
| | — |
|
| Increases related to the lapse of statute of limitations | | 1 |
| | — |
| | — |
| | 1 |
|
| Unrecognized tax benefits (detriments) – December 31, 2013 | | $ | 31 |
| | $ | (1 | ) | | $ | 60 |
| | $ | 90 |
|
| Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of December 31, 2011 | $ | 1 |
| | $ | 1 |
| | $ | — |
| $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates as of December 31, 2012 | $ | 1 |
| | $ | 3 |
| | $ | (1 | ) | $ | 3 |
| | $ | (1 | ) | | $ | (1 | ) | | $ | 1 |
|
| Total unrecognized tax benefits that, if recognized, would affect the effective tax rates as of December 31, 2013 | | $ | 3 |
| | $ | — |
| | $ | 51 |
| (b) | $ | 54 |
|
| |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries. |
| |
| (b) | Primarily due to tax positions relating to the New AER divestiture. The income statement impact of this unrecognized tax benefit was included in "Income (loss) from discontinued operations, net of taxes" on Ameren's consolidated statement of income (loss). See Note 16 – Divestiture Transactions and Discontinued Operations for additional information. |
The Ameren Companies recognize interest charges (income) and penalties accrued on tax liabilities on a pretax basis as interest charges (income) or miscellaneous expense, respectively, in the statements of income.
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 20102011, 20112012, and 20122013, is as follows:
|
| | | | | | | | | | | |
| | Ameren | | Ameren Missouri | | Ameren Illinois |
| Liability for interest - January 1, 2010 | $ | 8 |
| | $ | 4 |
| | $ | — |
|
| Interest charges for 2010 | 9 |
| | 6 |
| | 2 |
|
| Liability for interest - December 31, 2010 | $ | 17 |
| | $ | 10 |
| | $ | 2 |
|
| Interest income for 2011 | (11 | ) | | (3 | ) | | (1 | ) |
| Interest payment | (1 | ) | | (1 | ) | | — |
|
| Liability for interest - December 31, 2011 | $ | 5 |
| | $ | 6 |
| | $ | 1 |
|
| Interest charges for 2012 | 1 |
| | 2 |
| | — |
|
| Liability for interest - December 31, 2012 | $ | 6 |
| | $ | 8 |
| | $ | 1 |
|
|
| | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Ameren(a) |
| Liability for interest – January 1, 2011 | $ | 10 |
| | $ | 2 |
| | $ | 5 |
| | $ | 17 |
|
| Interest income for 2011 | (3 | ) | | (1 | ) | | (7 | ) | | (11 | ) |
| Interest payment | (1 | ) | | — |
| | — |
| | (1 | ) |
| Liability for interest – December 31, 2011 | $ | 6 |
| | $ | 1 |
| | $ | (2 | ) | | $ | 5 |
|
| Interest charges (income) for 2012 | 2 |
| | — |
| | (1 | ) | | 1 |
|
| Liability for interest – December 31, 2012 | $ | 8 |
| | $ | 1 |
| | $ | (3 | ) | | $ | 6 |
|
| Interest charges (income) for 2013 | (8 | ) | | (1 | ) | | 4 |
| | (5 | ) |
| Liability for interest – December 31, 2013 | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
As of December 31, 20102011, 20112012, and 20122013, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax benefits.
In 2011, a final settlement for the years 2005 and 2006 was reached with the Internal Revenue Service.IRS. It resulted in a reduction in uncertain tax liabilities of $39 million, $17 million and $12 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. Ameren’s federal income tax returns for the years 2007 through 20102011 are before the Appeals Office of the Internal Revenue Service.IRS. Ameren’s federal income tax return for the year 20112012 is currently under examination.
It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue ServiceIRS in the next twelve months for the years 2007 through 2010.2011. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $14320 million, $119 million, and $13 million for Ameren and Ameren Missouri, and Ameren Illinois, respectively. In addition.addition, it is reasonably possible that
other events will occur during the next 12twelve 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 any such increases or decreases, including the decrease from the reasonably possible IRS Appeals Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.
In 2013, unrecognized tax benefits related to the deductibility of expenditures to maintain, replace, or improve steam or electric power generation property, along with casualty loss deductions for storm damage, were reduced by $103 million, $95 million and $5 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. This reduction in unrecognized tax benefits did not impact overall income tax expense for the Ameren Companies. However, the liability for interest related to these unrecognized tax benefits has been released. In 2013, Ameren adopted an accounting method change as a result of the recent guidance issued by the IRS, establishing new rules for the amount and timing of the deductions to maintain, replace or improve generation property. In 2014, Ameren expects to adopt an accounting method change as a result of the recent guidance establishing new rules for the amount and timing of casualty loss deductions for storm damage.
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.
Ameren Missouri has an uncertain tax position tracker. Under Missouri's regulatory framework, uncertain tax positions do not reduce Ameren Missouri's electric rate base. When an uncertain income tax position liability is resolved, the MoPSC requires, through the uncertain tax position tracker, the creation of a regulatory asset or regulatory liability to reflect the time value, using the weighted-average cost of capital included in each of the electric rate orders in effect before the tax position was resolved, of the difference between the uncertain income tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will affect earnings in the year it is created and then will be amortized over three years beginning on the effective date of new rates established in the next electric rate case.
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.
Put Option Agreement and Guarantee139
On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gives Genco the option to sell to AERG all, but not less than all,
The put option agreement requires AERG to secure and maintain an Ameren guarantee of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guarantee agreement on March 28, 2012. The guarantee shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or until the put option agreement is terminated and no further payments are owed by AERG to Genco. As of December 31, 2012, Genco had not exercised the put option. Ameren and AERG do not expect to extend the put option agreement beyond March 28, 2014.
Electric Power Supply Agreements
Capacity Supply Agreements
Ameren Illinois, as an electric load-serving entity, must acquire capacity sufficient to meet its obligations to customers.
In 2009, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2009, through May 31, 2012. Both Marketing Company and Ameren Missouri were among the winning suppliers in the capacity RFP process. In April 2009, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $4 million, $9 million, and $8 million for the 12 months ending May 31, 2010, 2011, and 2012, respectively. In April 2009, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $2 million, $2 million, and $1 million for the 12 months ending May 31, 2010, 2011, and 2012, respectively.
In 2010, Ameren Illinois used aan RFP process, administered by the IPA, to contract capacity for the period from June 1, 2010, through May 31, 2013. Both Marketing Company and Ameren Missouri were among theAs a winning supplierssupplier in the capacity RFP process. In April 2010, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $1 million, $2 million, and $3 million for the 12 months ending May 31, 2011, 2012, and 2013, respectively. Inthis process, in April 2010, Ameren Missouri contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for less than $1$1 million for the period from June 1, 2010, through May 31, 2013.
DuringIn 2012, Ameren Illinois used aan RFP process, administered by the IPA, to contract capacity for the period from June 1, 2012, through May 31, 2015. Both Marketing Company and Ameren Missouri were among theAs a winning supplierssupplier in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois' capacity requirements for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively. Inthis process, in April 2012, Ameren Missouri contracted to supply a portion of Ameren Illinois' capacity requirements for $1$1 million and $3$3 million for the 12 months ending May 31, 2014, and 2015, respectively.
Energy Swaps and Energy Products
Ameren Illinois, as an electric load-serving entity, must acquire energy sufficient to meet its obligations to customers.
In 2009, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps from June 1, 2009, through May 31, 2011. Marketing Company was a winning supplier in the financial energy swap RFP process. In May 2009, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 80,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2010 and for approximately
89,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2011.
In 2010, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps for the period from June 1, 2010, through May 31, 2013. Marketing Company was a winning supplier in the financial energy swap RFP process. In May 2010, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 924,000 megawatthours at approximately $33 per megawatthour during the 12 months ending May 31, 2011 and for approximately 296,000 megawatthours at approximately $40 per megawatthour during the 12 months ending May 31, 2012.
In 2011, Ameren Illinois used aan RFP process, administered by the IPA, to procure energy products that will settle physically from June 1, 2011, through May 31, 2014. Marketing Company and Ameren Missouri werewas among the winning suppliers in Ameren Illinois’the energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements by which Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the 12 months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2013, and approximately 650,000 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2014. In May 2011, Ameren Missouri and Ameren Illinois entered into energy product agreements by which Ameren Missouri willagreed to sell and Ameren Illinois willagreed to purchase approximately 16,800 megawatthours at approximately $37$37 per megawatthour during the 12 months ending May 31, 2012, approximately 40,800 megawatthours at approximately $29$29 per megawatthour during the 12 months ending May 31, 2013, and approximately 40,800 megawatthours at approximately $28$28 per megawatthour during the 12 months ending May 31, 2014. The May 31, 2012 and May 31, 2013 energy product agreements between Ameren Missouri and Ameren Illinois arefor the periods ending May 31, 2012, and May 31, 2013, were for off-peak hours only.
In February 2012, a rate stability procurement for energy products that will settle physically was administered by the IPA for the June 2013 through May 2017 period to meet certain requirements for purchased power related to the IEIMA. Marketing Company was a winning supplier in Ameren Illinois’ energy product procurement process. In February 2012, Marketing Company and Ameren Illinois entered into energy product agreements pursuant to which Marketing Company will sell and Ameren Illinois will purchase approximately 3,942,000 megawatthours at approximately $30 per megawatthour during the 12 months ending May 31, 2014, approximately 3,504,000 megawatthours at approximately $32 per megawatthour during the 12 months ending May 31, 2015, and approximately 1,317,600 megawatthours at approximately $34 per megawatthour during the 12 months ending May 31, 2016. The energy product agreements were based on around-the-clock prices.
Interconnection and Transmission Agreements
Ameren Missouri and Ameren Illinois are parties to an interconnection agreement for the use of their respective transmission lines and other facilities for the distribution of power. These agreements have no contractual expiration date, but may be terminated by either party with three years’ notice.
Joint Ownership Agreement
ATXI and Ameren Illinois have a joint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this agreement, Ameren Illinois and ATXI are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. Ameren is the primary beneficiary of ATXI, which is a variable interest entity, and therefore consolidates ATXI. Currently, there are no construction projects or joint ownership of existing assets under this agreement.
In January 2011, ATXI repaid advances for the construction of transmission assets to Ameren Illinois in the amount of $52 million, including $3 million of accrued interest.
In April 2011, ATXI transferred, at cost, all of ATXI’s construction work in progress assets related to the construction of a transmission line to Ameren Illinois for $20 million.
Support Services Agreements
Ameren Services provides support services to its affiliates. The costs of support services, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. The shared services support agreement can be terminated with respect to a particular affiliate by the mutual agreement of Ameren Services and that affiliate or by either Ameren Services or that affiliate with 60 daysdays' notice before the end of a calendar year. Ameren has begun planning how it will to reduce, and ultimately eliminate AER's reliance on the support services agreement.
AFS provided support services to its affiliates through December 31, 2010. Effective January 1, 2011, the services previously performed by AFS are performed within Ameren Missouri, Ameren Illinois and AER.
In addition, Ameren Missouri and Ameren Illinois and AER provide affiliates, primarily Ameren Services, with access to their facilities for administrative purposes. The cost of the rent and facility services are based on, or are an allocation of, actual costs incurred.
Gas SalesSeparately, Ameren Missouri and Transportation AgreementAmeren Illinois provide storm-related and miscellaneous support services to each other on an as-needed basis.
Under a gas transportation agreement, Genco acquires gas transportationTransmission Services
Ameren Illinois must take transmission service from Ameren Missouri. This agreement expiresMISO for the retail load it serves in February 2016.
Transmission Services Agreement
Under athe transmission services agreement, Marketing Company acquiresowners in the AMIL pricing zone. Accordingly ATXI receives transmission servicespayments from Ameren Illinois for certain retail and residential customers.through the MISO billing process.
Money PoolsPool
See Note 4 – Short-term Debt and Liquidity and Note 5 -– Long-term Debt and Equity Financings for a discussion of affiliate borrowing arrangements.
Collateral Postings
Under the terms of the Illinois power procurement agreements entered into through RFP processes administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning
that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, and Marketing Company, as a winning supplierssupplier in the RFP process, may be required to post collateral. As of December 31, 20122013, and 20112012, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.
Marketing Company Sale of Trade Receivables to Ameren Illinois
In accordance with the Illinois Public Utilities Act, Ameren Illinois is required to purchase alternative retail electric suppliers' receivables relating to Ameren Illinois' delivery service customers who elected to receive power supply from the alternative retail electric supplier. Beginning in June 2012, Marketing Company sold and Ameren Illinois purchased trade receivables relating to the power supply of residential customers using Marketing Company as their alternative retail electric supplier. Marketing Company has no continuing involvement with or control over the trade receivables after the sale is completed to Ameren Illinois, and neither company has any restrictions on the assets associated with these purchase and sale transactions. As of December 31, 2012, Ameren Illinois' payable to Marketing Company for the purchase of trade receivables totaled $5 million. For the year ended December 31, 2012, Ameren Illinois purchased $35 million of trade receivables from Marketing Company at a discount of less than $1 million. Marketing Company's receivable from Ameren Illinois as well as Ameren Illinois' payable to Marketing Company are eliminated in the consolidated Ameren Corporation's financial statements.
Intercompany Sales
In 2012, Genco completed the sale of land for cash proceeds of $2 million to ATXI. Genco recognized a $2 million gain from the sale. Under authoritative accounting guidance for rate-regulated entities, the gain was not eliminated upon consolidation.
Parent Company Guarantees
In the ordinary course of business, Ameren (parent) enters
into various agreements providing financial assurance to third parties on behalf of its subsidiaries. Such agreements include, for example, guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit and reducing the amount of cash collateral required to be posted. These agreements guarantee performance by Ameren's subsidiaries of obligations already existing on Ameren's consolidated balance sheet.
Upon the ultimate exit of the Merchant Generation segment, the guarantees relative to that business segment that are in effect at that time may or may not be retained by Ameren (parent), depending on the terms of Ameren's exit from that business.
At December 31, 2012, Ameren had a total of $354 million in guarantees outstanding, which included:
$189 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. Of these guarantees $161 million expire in 2013, $12 million expire in 2014, and $16 million expire thereafter. Ameren remains obligated under these guarantees, up to the maximum level included in the respective guarantee agreements, after the guarantee expiration date if transactions between the counterparties were in effect at the expiration of the guarantee agreement. Consequently, Ameren's guarantees may be extended past the expiration dates listed above depending on future counterparty transactions. The amounts above do not represent incremental consolidated Ameren obligations; rather, they represent Ameren parental guarantees of subsidiary obligations to third parties in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren's estimated exposure for obligations under transactions covered by these guarantees was $25 million at December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices.
$100 million associated with the guarantee agreement between Ameren and AERG entered into on March 28, 2012, relating to the put option agreement between Genco and AERG. As of December 31, 2012, Genco had not exercised the put option and thus Ameren had no exposure to this intercompany guarantee.
$50 million guarantee to MISO for all of Ameren's subsidiaries who are MISO market participants. Ameren's estimated exposure for obligations under transactions covered by this guarantee was $32 million at December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices.
$15 million related to requirements for asset transactions, leasing, and other service agreements. At December 31, 2012, Ameren estimated it had no exposure to any of these guarantees.
Additionally, at December 31, 2012, Ameren had issued letters of credit totaling $9 million as credit support to certain subsidiaries.
The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the years ended December 31, 20122013, 20112012, and 20102011. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 -– Short-term Debt and Liquidity.
| | | Agreement | Income Statement Line Item | | | | Ameren Missouri | | Ameren Illinois | Income Statement Line Item | | | | Ameren Missouri | | Ameren Illinois |
| Ameren Missouri power supply agreements | Operating Revenues | | 2012 | | $(b) |
| | $(a) |
| Operating Revenues | | 2013 | $ | 3 |
| $ | (a) |
|
| with Ameren Illinois | | 2011 | | 2 |
| | (a) |
| | 2012 | | (b) |
| | (a) |
|
| | | | 2010 | | 2 |
| | (a) |
| | | 2011 | | 2 |
| | (a) |
|
| Ameren Missouri and Genco gas | Operating Revenues | | 2012 | | 1 |
| | (a) |
| |
| transportation agreement | | 2011 | | 1 |
| | (a) |
| |
| | | | 2010 | | 1 |
| | (a) |
| |
| Ameren Missouri and Ameren Illinois | Operating Revenues | | 2012 | | 19 |
| | 1 |
| Operating Revenues | | 2013 | | 21 |
| | 1 |
|
| rent and facility services | | 2011 | | 16 |
| | 1 |
| | 2012 | | 19 |
| | 1 |
|
| | | | 2010 | | 16 |
| | 1 |
| | | 2011 | | 16 |
| | 2 |
|
| Ameren Illinois transmission services agreement | Operating Revenues | | 2012 | | (a) |
| | 15 |
| |
| with Marketing Company | | 2011 | | (a) |
| | 10 |
| |
| Ameren Missouri and Ameren Illinois | | Operating Revenues | | 2013 | | 1 |
| | 3 |
|
| miscellaneous support services | | | 2012 | | 1 |
| | (b) |
|
| | | 2010 | | (a) |
| | 10 |
| | 2011 | | 5 |
| | 1 |
|
| Total Operating Revenues | | 2012 | | $ | 20 |
| | $ | 16 |
| | 2013 | $ | 25 |
| $ | 4 |
|
| | | 2011 | | 19 |
| | 11 |
| | 2012 | | 20 |
| | 1 |
|
| | | | 2010 | | 19 |
| | 11 |
| | | 2011 | | 23 |
| | 3 |
|
| Ameren Illinois power supply agreements | Purchased Power | | 2012 | | $(a) |
| | $ | 311 |
| |
| with Marketing Company | | 2011 | | (a) |
| | 232 |
| |
| | | | 2010 | | (a) |
| | 233 |
| |
| Ameren Illinois power supply | Purchased Power | | 2012 | | (a) |
| | (b) |
| Purchased Power | | 2013 | $ | (a) |
| $ | 3 |
|
| agreements with Ameren Missouri | | 2011 | | (a) |
| | 2 |
| | 2012 | | (a) |
| | (b) |
|
| | | | | 2011 | | (a) |
| | 2 |
|
| Ameren Illinois transmission | | Purchased Power | | 2013 | | (a) |
| | 2 |
|
| services with ATXI | | | 2012 | | (a) |
| | 3 |
|
| | | | 2010 | | (a) |
| | 2 |
| | 2011 | | (a) |
| | 3 |
|
| Total Purchased Power | | 2012 | | $(a) |
| | $ | 311 |
| | 2013 | $ | (a) |
| $ | 5 |
|
| | | 2011 | | (a) |
| | 234 |
| | 2012 | | (a) |
| | 3 |
|
| | | | 2010 | | (a) |
| | 235 |
| | 2011 | | (a) |
| | 5 |
|
| Gas purchases from Genco | Gas Purchased for Resale | | 2012 | | $(a) |
| | $ | — |
| |
| | | 2011 | | (a) |
| | — |
| |
| | | | 2010 | | (a) |
| | 1 |
| |
| Ameren Services support services | Other Operations and | | 2012 | | $ | 106 |
| | $ | 88 |
| Other Operations and | | 2013 | $ | 116 |
| $ | 93 |
|
| agreement | Maintenance | | 2011 | | 114 |
| | 87 |
| Maintenance | | 2012 | | 106 |
| | 88 |
|
| | | | 2010 | | 128 |
| | 102 |
| |
| AFS support services agreement | Other Operations and | | 2012 | | (a) |
| | (a) |
| |
| | Maintenance | | 2011 | | (a) |
| | (a) |
| |
| | | | 2010 | | 7 |
| | (b) |
| | | 2011 | | 114 |
| | 87 |
|
Insurance premiums(c) | Other Operations and | | 2012 | | (b) |
| | (a) |
| Other Operations and | | 2013 | | (b) |
| | (a) |
|
| | Maintenance | | 2011 | | (b) |
| | (a) |
| Maintenance | | 2012 | | (b) |
| | (a) |
|
| | | | 2010 | | 1 |
| | (a) |
| | | 2011 | | (b) |
| | (a) |
|
| Total Other Operations and | | 2012 | | $ | 106 |
| | $ | 88 |
| | 2013 | $ | 116 |
| $ | 93 |
|
| Maintenance Expenses | | 2011 | | 114 |
| | 87 |
| | 2012 | | 106 |
| | 88 |
|
| | | | 2010 | | 136 |
| | 102 |
| | | 2011 | | 114 |
| | 87 |
|
| Money pool borrowings (advances) | Interest (Charges) | | 2012 | | $(b) |
| | $(b) |
| Interest (Charges) | | 2013 | $ | (b) |
| $ | (b) |
|
| | Income | | 2011 | | — |
| | — |
| Income | | 2012 | | (b) |
| | (b) |
|
| | | | 2010 | | — |
| | — |
| | | 2011 | | — |
| | — |
|
| |
| (b) | Amount less than $1 million. |
| |
| (c) | Represents insurance premiums paid to Energy Risk Assurance Company, an affiliate for replacement power, property damage, and terrorism coverage. |
NOTE 15 -– COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax, and regulatory proceedings before various courts, regulatory commissions, authorities, 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 Energy
Center, and Note 14 -– Related Party Transactions, and Note 16 – Divestiture Transactions and Discontinued Operations in this report.
Callaway Energy Center
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at December 31, 20122013. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.
| | | Type and Source of Coverage | Maximum Coverages | | Maximum Assessments | | Maximum Coverages | | Maximum Assessments | |
| Public liability and nuclear worker liability: | | | | | | | | |
| American Nuclear Insurers | $ | 375 |
|
| $ | — |
| | $ | 375 |
|
| $ | — |
| |
| Pool participation | 12,219 |
| (a) | 118 |
| (b) | 13,241 |
| (a) | 128 |
| (b) |
| | $ | 12,594 |
| (c) | $ | 118 |
| | $ | 13,616 |
| (c) | $ | 128 |
| |
| Property damage: | | | | | | | | |
| Nuclear Electric Insurance Ltd. | $ | 2,750 |
| (d) | $ | 23 |
| (e) | |
| Nuclear Electric Insurance Limited | | $ | 2,250 |
| (d) | $ | 23 |
| (e) |
| European Mutual Association for Nuclear Insurance | | 500 |
| (f) | — |
| |
| | | $ | 2,750 |
| | $ | 23 |
| |
| Replacement power: | | | | | | | | |
| Nuclear Electric Insurance Ltd | $ | 490 |
| (f) | $ | 9 |
| (e) | |
| Energy Risk Assurance Company | $ | 64 |
| (g) | $ | �� |
| | |
| Nuclear Electric Insurance Limited | | $ | 490 |
| (g) | $ | 9 |
| (e) |
| Missouri Energy Risk Assurance Company | | $ | 64 |
| (h) | $ | — |
| |
| |
| (a) | Provided through mandatory participation in an industrywide retrospective premium assessment program. |
| |
| (b) | Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S.United States commercial reactor, payable at $17.519 million per year. |
| |
| (c) | Limit of liability for each incident under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118128 million per incident for each licensed reactor it operates with a maximum of $17.519 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors. |
| |
| (d) | Provides for $500 millionNuclear Electric Insurance Limited provides $2.25 billion in property damage, and decontamination, excess property insurance, and premature decommissioning insurance. There is a $1.7 billion sublimit for non-radiation events, of which the top $200 million is a shared limit with other generators purchasing this coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
and includes one free reinstatement. |
| |
| (e) | All Nuclear Electric Insurance Ltd.Limited insured plants could be subject to assessments should losses exceed the accumulated funds from Nuclear Electric Insurance Ltd.Limited. |
| |
| (f) | European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage and $1.7 billion non-radiation coverage. |
| |
| (g) | Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Effective April 1, 2013, non-radiation events are sub-limited to $327.6 million. |
| |
(g)(h) | Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd.Limited and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 -– Related Party Transactions for more information on this affiliate transaction. |
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. 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. The next adjustment could occur during the fourth quarter ofSeptember 10, 2013. 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 the Price-Anderson Act.
Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd’sLimited’s policies, subject to an industrywide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri 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 Ameren Missouri’s results of operations, financial position, or liquidity.
Leases
We lease various facilities, office equipment, plant equipment, and rail cars under capital and operating leases. The following table presents our lease obligations at December 31, 20122013:
| | | | Total | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | After 5 Years | Total | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | After 5 Years |
Ameren:(a) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital lease payments(b) | $ | 588 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 33 |
| | $ | 33 |
| | $ | 425 |
| |
Minimum capital lease payments(b) | | $ | 556 |
| | $ | 32 |
| | $ | 33 |
| | $ | 33 |
| | $ | 33 |
| | $ | 32 |
| | $ | 393 |
|
| Less amount representing interest | 284 |
| | 27 |
| | 27 |
| | 27 |
| | 27 |
| | 27 |
| | 149 |
| 257 |
| | 27 |
| | 27 |
| | 27 |
| | 27 |
| | 26 |
| | 123 |
|
| Present value of minimum capital lease payments | $ | 304 |
| | $ | 5 |
| | $ | 5 |
| | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 276 |
| $ | 299 |
| | $ | 5 |
| | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 270 |
|
Operating leases(c) | 272 |
| | 31 |
| | 27 |
| | 26 |
| | 26 |
| | 25 |
| | 137 |
| 117 |
| | 14 |
| | 13 |
| | 13 |
| | 13 |
| | 13 |
| | 51 |
|
| Total lease obligations | $ | 576 |
| | $ | 36 |
| | $ | 32 |
| | $ | 32 |
| | $ | 32 |
| | $ | 31 |
| | $ | 413 |
| $ | 416 |
| | $ | 19 |
| | $ | 19 |
| | $ | 19 |
| | $ | 19 |
| | $ | 19 |
| | $ | 321 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital lease payments(b) | $ | 588 |
| | $ | 32 |
| | $ | 32 |
| | $ | 33 |
| | $ | 33 |
| | $ | 33 |
| | $ | 425 |
| |
Minimum capital lease payments(b) | | $ | 556 |
| | $ | 32 |
| | $ | 33 |
| | $ | 33 |
| | $ | 33 |
| | $ | 32 |
| | $ | 393 |
|
| Less amount representing interest | 284 |
| | 27 |
| | 27 |
| | 27 |
| | 27 |
| | 27 |
| | 149 |
| 257 |
| | 27 |
| | 27 |
| | 27 |
| | 27 |
| | 26 |
| | 123 |
|
| Present value of minimum capital lease payments | $ | 304 |
| | $ | 5 |
| | $ | 5 |
| | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 276 |
| $ | 299 |
| | $ | 5 |
| | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| | $ | 270 |
|
Operating leases(c) | 123 |
| | 12 |
| | 12 |
| | 12 |
| | 12 |
| | 13 |
| | 62 |
| 106 |
| | 11 |
| | 11 |
| | 11 |
| | 12 |
| | 11 |
| | 50 |
|
| Total lease obligations | $ | 427 |
| | $ | 17 |
| | $ | 17 |
| | $ | 18 |
| | $ | 18 |
| | $ | 19 |
| | $ | 338 |
| $ | 405 |
| | $ | 16 |
| | $ | 17 |
| | $ | 17 |
| | $ | 18 |
| | $ | 17 |
| | $ | 320 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating leases(c) | $ | 7 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
| $ | 7 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
| |
| (b) | See Properties under Part I, Item 2, and Note 3 -– Property and Plant, Net, of this report for additional information. |
| |
| (c) | Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million, $1 million and $1 million for Ameren, Ameren Missouri and Ameren Illinois for these items is included in the 20132014 through 20172018 columns, respectively. |
The following table presents total rental expense, included in operating expenses, for the years ended December 31, 20122013, 20112012, and 20102011:
| | | | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
Ameren(a) | $ | 48 |
| | $ | 47 |
| | $ | 52 |
| $ | 32 |
| | $ | 33 |
| | $ | 36 |
|
| Ameren Missouri | 29 |
| | 29 |
| | 29 |
| 29 |
| | 29 |
| | 29 |
|
| Ameren Illinois | 19 |
| | 17 |
| | 19 |
| 21 |
| | 19 |
| | 17 |
|
| |
| (a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Other Obligations
To supply a portion of the fuel requirements of our energy centers, 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 purchased power and natural gas for distribution. The table below presents our estimated fuel, purchased power, and other commitments at December 31, 20122013. Ameren’s and Ameren Missouri’s purchased power obligations include a 102-megawatt power purchase agreement with a wind farm operator that expires in 2024. Ameren’s and Ameren Illinois’ purchased power obligations include the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services at December 31, 20122013. Ameren's and Ameren Illinois' Other column also include obligations related to IEIMA. In addition, the Other column includes Ameren's and Ameren Missouri's obligations related to energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147expects to incur $48 million over three years in 2014 and $64 million in 2015 for these energy efficiency programs. See Note 2 -– Rate and Regulatory Matters for additional information about the IEIMA and MEEIA.
| | | | Coal | | Natural Gas | | Nuclear Fuel | | Purchased Power(a) | | Methane Gas | | Other | | Total | Coal | | Natural Gas(a) | | Nuclear Fuel | | Purchased Power(b) | | Methane Gas | | Other | | Total |
Ameren:(b)(c) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | $ | 908 |
| | $ | 349 |
| | $ | 36 |
| | $ | 421 |
| | $ | 3 |
| | $ | 174 |
| | $ | 1,891 |
| |
| 2014 | 774 |
| | 254 |
| | 89 |
| | 309 |
| | 3 |
| | 167 |
| | 1,596 |
| $ | 620 |
| | $ | 323 |
| | $ | 64 |
| | $ | 308 |
| | $ | 3 |
| | $ | 201 |
| | $ | 1,519 |
|
| 2015 | 702 |
| | 138 |
| | 87 |
| | 164 |
| | 4 |
| | 117 |
| | 1,212 |
| 642 |
| | 179 |
| | 63 |
| | 164 |
| | 4 |
| | 143 |
| | 1,195 |
|
| 2016 | 732 |
| | 54 |
| | 95 |
| | 78 |
| | 4 |
| | 62 |
| | 1,025 |
| 664 |
| | 90 |
| | 81 |
| | 78 |
| | 4 |
| | 76 |
| | 993 |
|
| 2017 | 701 |
| | 34 |
| | 78 |
| | 55 |
| | 5 |
| | 50 |
| | 923 |
| 676 |
| | 45 |
| | 58 |
| | 55 |
| | 4 |
| | 50 |
| | 888 |
|
| 2018 | | 120 |
| | 28 |
| | 57 |
| | 52 |
| | 5 |
| | 51 |
| | 313 |
|
| Thereafter | 277 |
| | 105 |
| | 277 |
| | 687 |
| | 99 |
| | 246 |
| | 1,691 |
| 125 |
| | 82 |
| | 158 |
| | 635 |
| | 91 |
| | 350 |
| | 1,441 |
|
| Total | $ | 4,094 |
| | $ | 934 |
| | $ | 662 |
| | $ | 1,714 |
| | $ | 118 |
| | $ | 816 |
| | $ | 8,338 |
| $ | 2,847 |
| | $ | 747 |
| | $ | 481 |
| | $ | 1,292 |
| | $ | 111 |
| | $ | 871 |
| | $ | 6,349 |
|
| Ameren Missouri: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | $ | 620 |
| | $ | 57 |
| | $ | 36 |
| | $ | 19 |
| | $ | 3 |
| | $ | 106 |
| | $ | 841 |
| |
| 2014 | 625 |
| | 43 |
| | 89 |
| | 19 |
| | 3 |
| | 123 |
| | 902 |
| $ | 620 |
| | $ | 62 |
| | $ | 64 |
| | $ | 19 |
| | $ | 3 |
| | $ | 127 |
| | $ | 895 |
|
| 2015 | 614 |
| | 25 |
| | 87 |
| | 19 |
| | 4 |
| | 87 |
| | 836 |
| 642 |
| | 32 |
| | 63 |
| | 19 |
| | 4 |
| | 101 |
| | 861 |
|
| 2016 | 644 |
| | 10 |
| | 95 |
| | 19 |
| | 4 |
| | 38 |
| | 810 |
| 664 |
| | 19 |
| | 81 |
| | 19 |
| | 4 |
| | 40 |
| | 827 |
|
| 2017 | 676 |
| | 5 |
| | 78 |
| | 19 |
| | 5 |
| | 26 |
| | 809 |
| 676 |
| | 11 |
| | 58 |
| | 19 |
| | 4 |
| | 26 |
| | 794 |
|
| 2018 | | 120 |
| | 8 |
| | 57 |
| | 19 |
| | 5 |
| | 27 |
| | 236 |
|
| Thereafter | 245 |
| | 28 |
| | 277 |
| | 130 |
| | 99 |
| | 144 |
| | 923 |
| 125 |
| | 28 |
| | 158 |
| | 110 |
| | 91 |
| | 183 |
| | 695 |
|
| Total | $ | 3,424 |
| | $ | 168 |
| | $ | 662 |
| | $ | 225 |
| | $ | 118 |
| | $ | 524 |
| | $ | 5,121 |
| $ | 2,847 |
| | $ | 160 |
| | $ | 481 |
| | $ | 205 |
| | $ | 111 |
| | $ | 504 |
| | $ | 4,308 |
|
| Ameren Illinois: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | $ | — |
| | $ | 270 |
| | $ | — |
| | $ | 401 |
| | $ | — |
| | $ | 24 |
| | $ | 695 |
| |
| 2014 | — |
| | 206 |
| | — |
| | 289 |
| | — |
| | 22 |
| | 517 |
| $ | — |
| | $ | 261 |
| | $ | — |
| | $ | 289 |
| | $ | — |
| | $ | 23 |
| | $ | 573 |
|
| 2015 | — |
| | 110 |
| | — |
| | 145 |
| | — |
| | 24 |
| | 279 |
| — |
| | 147 |
| | — |
| | 145 |
| | — |
| | 24 |
| | 316 |
|
| 2016 | — |
| | 44 |
| | — |
| | 59 |
| | — |
| | 24 |
| | 127 |
| — |
| | 71 |
| | — |
| | 59 |
| | — |
| | 24 |
| | 154 |
|
| 2017 | — |
| | 29 |
| | — |
| | 36 |
| | — |
| | 24 |
| | 89 |
| — |
| | 34 |
| | — |
| | 36 |
| | — |
| | 24 |
| | 94 |
|
| 2018 | | — |
| | 20 |
| | — |
| | 33 |
| | — |
| | 24 |
| | 77 |
|
| Thereafter | — |
| | 78 |
| | — |
| | 559 |
| | — |
| | 102 |
| | 739 |
| — |
| | 54 |
| | — |
| | 525 |
| | — |
| | 167 |
| | 746 |
|
| Total | $ | — |
| | $ | 737 |
| | $ | — |
| | $ | 1,489 |
| | $ | — |
| | $ | 220 |
| | $ | 2,446 |
| $ | — |
| | $ | 587 |
| | $ | — |
| | $ | 1,087 |
| | $ | — |
| | $ | 286 |
| | $ | 1,960 |
|
| |
| (a) | Includes amounts for generation and for distribution. |
| |
| (b) | The purchased power amounts for Ameren and Ameren Illinois includesinclude 20-year agreements for renewable energy credits that were entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits. |
| |
(b)(c) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
Previously, Ameren Illinois has entered into an agreement, through a process administered by the IPA, to purchase approximately 15.5 billion cubic feet of synthetic natural gaspower from a repowered unit at the Meredosia energy center designed for permanent carbon dioxide capture and storage, annually over a 10-year20-year period beginning in 20162017, for its natural gaselectric delivery service customers. The agreement was entered into pursuant to an Illinois law, that became effective August 2, 2011. Ameren Illinois' obligations under the agreement wereis contingent on the counterpartyparties interested in repowering the unit at the abandoned Meredosia energy center reaching certain milestones during the project development andrelated to the construction and commencement of operations of this unit. Ameren will not repower the unit; however, a sale of the unit to a third party is possible. Construction has not begun on the unit at this energy center; therefore, Ameren Illinois’ obligations are not certain at this time and consequently not included in the table above. If the plant that was to produceis not in service by 2019, Ameren Illinois can terminate the synthetic natural gas. The counterparty failed to meet certain milestones during 2012 and, accordingly, the contract was terminated.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,generation, transmission and
distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, discharges to water, water usage,
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 and renew approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requiresrequire release prevention plans and emergency response procedures.
In addition to existing laws and regulations, including the Illinois MPS that applies to AER's energy centers in Illinois, theThe EPA is developing environmental regulations that will have a significant impact on the electric utility industry. TheseOver time, compliance with these regulations could be particularly burdensomecostly for certain companies, including Ameren Ameren Missouri, Genco and AERG, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions;CO2 emissions from new energy centers; revised national ambient air quality standards for ozone, fine particulate,particulates, SO2, and NO2x emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new effluent standards applicable to waste water discharges from energy centers and new regulations under the Clean Water Act that could require significant capital expenditures, such as newmodifications to water intake structures or new cooling towers at our energy centers. The EPA has proposedis expected to propose CO2 limitsstandards for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing fossil fuel-fired electric generation units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012.uncertain. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/orand increased operating costs over the next five to ten years for Ameren and Ameren Missouri and AER.Missouri. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulationsexpensive or could require us to closeresult in the closure or to significantly alteralteration of the operation of some of our energy centers, whichcenters. Ameren and Ameren Missouri would expect these costs to be recoverable through rates, but the nature and timing of costs, as well as the applicable regulatory framework, could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.regulatory lag.
The estimates inAs of December 31, 2013, Ameren and Ameren Missouri estimate capital expenditure investments of $275 million to $350 million over the table below contain all of the known capital costsnext five years to comply with existing environmental regulations, including the CAIR, and our assessment of the potential impacts of the EPA's proposed regulation for CCR and the finalized MATS as of December 31, 2012. The estimates in the table below assumeregulations. This estimate assumes that CCR will continue to be regardedregulated as nonhazardous. The estimates in the table below doThis estimate does not include the impacts of regulations proposed by the EPA under the Clean Water Act, in March 2011, regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013, as our evaluationthe technology requirements of those impacts is ongoing.these final rules are not yet known. Considerable uncertainty remains in this estimate. The estimates inactual amount of capital expenditure investments to comply with existing environmental regulations may vary substantially from the table below assumeabove estimate due to uncertainty as to the Merchant Generation facilities are owned by Ameren over the entire period shown. The estimates shown in the table below could change significantly depending upon a variety of factors including:
additional or modified federal or state requirements;
further regulation of greenhouse gas emissions;
revisions to CAIR or reinstatement of CSAPR;
new national ambient air quality standards or changes toprecise compliance strategies that will be used and their ultimate cost, among other things.
Ameren Missouri's current environmental compliance plan for air emissions includes burning ultra-low-sulfur coal and installing new or optimizing existing standards for ozone, fine particulates,pollution control equipment. Ameren Missouri has two scrubbers at its Sioux energy center, which are used to reduce SO2, emissions and NOx emissions;other pollutants. Currently, Ameren Missouri's compliance plan assumes the installation of additional controls including mercury control technology and precipitator upgrades at multiple energy centers within its coal-fired fleet during the next five years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the MATS and other recently finalized or proposed EPA regulations. Additional controls may be necessary, depending upon the resolution of the CSAPR litigation currently pending before the United States Supreme Court or if a new rule replacing CAIR is ultimately adopted, as discussed below. If CSAPR is implemented, Ameren Missouri may be required to install two additional scrubbers within the next ten years.
Environmental compliance costs at some of Ameren Missouri's energy centers could be prohibitive and additional rules governing air pollutant transport;
regulations under the Clean Water Act regarding cooling water intake structurescapital investment or effluent standards;
finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;
new technology;
expected power prices;
variationscontinued operations unwarranted. Ameren Missouri's capital expenditures and other costs are subject to MoPSC prudence reviews, which could result in costs of material or labor; and
alternative compliance strategies or investment decisions.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | 2013 | 2014 - 2017 | 2018 - 2022 | Total |
AMO(a) | $ | 105 |
| $ | 215 |
| - | $ | 260 |
| $ | 795 |
| - | $ | 975 |
| $ | 1,115 |
| - | $ | 1,340 |
|
| Genco | 30 |
| 100 |
| - | 125 |
| 220 |
| - | 270 |
| 350 |
| - | 425 |
|
| AERG | 5 |
| 20 |
| - | 25 |
| 20 |
| - | 25 |
| 45 |
| - | 55 |
|
| Ameren | $ | 140 |
| $ | 335 |
| - | $ | 410 |
| $ | 1,035 |
| - | $ | 1,270 |
| $ | 1,510 |
| - | $ | 1,820 |
|
| |
(a) | Ameren Missouri’s expenditures are expected to be recoverable from ratepayers. |
The decision to make pollution control equipment investments at AER depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in that year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices,disallowances as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. The table above includes Genco's estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for the construction of the two Newton energy center scrubbers. Based on the MPS variance granted by the Illinois Pollution Control Board in September 2012, AER is currently scheduled to complete the Newton scrubbers by the end of 2019. See additional information below regarding the MPS variance granted by the Illinois Pollution Control Board.regulatory lag.
The following sections describe the more significant environmental laws and rules that affect or could affect our operations.
Clean Air Act
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions.
In December 2008, the United States Court of Appeals for the District of Columbia Circuit found various aspects of the law to be unlawful and remanded the CAIR to the EPA for further action, to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as
the CAIR replacement. The CSAPR was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, with further reductions in 2014. On December 30, 2011,regulations were vacated by the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012,Circuit. The EPA appealed to the United States Supreme Court, of Appeals for the District of Columbia Circuit issuedand a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing.is expected by June 2014. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or until the United States Supreme Court overturns the decision to vacate the CSAPR is overturned by the United States Supreme Court.CSAPR.
In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury and particulate matter that are not currently in place.emissions. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016. Ameren Missouri's
Labadie and Meramec energy centers requested and were granted extensions to comply with the MATS by April 2016.
Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to energy centers but could require reductions in SO2 and NOx emissions. Compliance with the finalized rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren Missouri and AER are currently evaluating the new standard while the states of Missouri and Illinois develop their attainment plans.
In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard for ozone again in 2013. The states of Illinois and Missouri will be required to develop attainment plans2016 to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control requirements for power plants by 2020. Ameren, Ameren Missouri and AER continue to assess the impacts of these new standards.
Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-
low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren Missouri's energy centers have historically burned, which allowed Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet, mercury control technology, and precipitator upgrades at multiple energy centers during the next 10 years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the MATS and other recently finalized or proposed EPA regulations.
In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO2 emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board's order also included the following provisions:
A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at Genco's Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.
A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact Genco's ability to make the Meredosia energy center available for any parties that may be interested in repowering one of its units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.
Under the MPS, AER is required to reduce mercury and NOx emissions by 2015 and SO2 emissions by the end of 2019. The Illinois Pollution Control Board's September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NOx, and SO2. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco's Newton energy center. AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.
Environmental compliance costs could be prohibitive at some of Ameren's, Ameren Missouri's and AER's energy centers
as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.MATS.
Emission Allowances
The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations. The CAIR uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. Ameren and Ameren Missouri expectexpects to have adequateenough CAIR allowances for 20132014 to avoid needing to makemaking external purchases to comply with these programs.
Global Climate Change
State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation 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-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. The enactment of a climate change law could result in a significant rise in rates for electricity and thereby household costs. 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 about half as much CO2 as coal when burned to produce electricity. Therefore, climate change regulations 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, economywide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.Greenhouse Gas Regulation
In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.
Recognizing the difficulties presented by regulating at once
virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011 for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that when renewed, may behave been modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources or new major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule.
Separately, Industry groups and a coalition of states filed petitions in March 2012,April 2013 requesting that the United States Supreme Court review the circuit court's decision. In October 2013, the United States Supreme Court granted limited review of one petition, agreeing to consider whether the Clean Air Act authorizes the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS forto regulate emissions of greenhouse gases from stationary sources, including power plants, as a result of its determination to regulate greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not affect any of Ameren's or Ameren Missouri's existing energy centers. Ameren anticipates this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive.from motor vehicles. A final ruleruling is expected in 2013. Any federal climate change legislation2014.
In June 2013, the Obama administration announced that is enacted may preemptit had directed the EPA's regulationEPA to set CO2 emissions standards for both new and existing power plants. The EPA published proposed regulations in January 2014 that would set revised CO2 emissions standards for new electricity generating units. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In addition, the Obama administration directed the EPA to propose a CO2 emissions standard for existing power plants by June 2014
and to finalize such standard by June 2015. Currently, the Ameren Companies are unable to predict the outcome or impacts of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants.such future regulations.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likelymay 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 Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and AER as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity.
Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In March 2012, the United States District Court for the Southern District of
Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including Ameren Missouri, Genco, and AERG, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. The case has been appealed to the appellate court.
The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, their impact on our coal-fired energy centers and our customers' costs is unknown, but they could result in significant increases in our capital expenditures and operating costs. TheThese compliance costs could be prohibitive at some of our energy centers, as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.assets if costs are not recovered through rates. To the extent that Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery. Mandatory limits on the emission of greenhouse gases could increase costs for our customers or have a material adverse impact on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity. To the extent investments in environmental control technology are reflected and recovered on a timely basis in rate base, Ameren's and Ameren Missouri's earnings may benefit from increased investment in such control technology.
NSR and Clean Air Litigation
The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.
Commencing in 2005, Genco received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at Genco's Newton energy center violated federal law. Genco believes its defenses to the allegations described in the Notice of Violation are meritorious. Ameren and Genco are unable to predict the outcome of this matter and whether EPA will address this Notice of Violation administratively or through litigation.
Following the issuance of a Notice of Violation, in January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint, as amended in October 2013, alleges that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States DistrictCourt granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for unspecified injunctive relief including to require the installation of
pollution control equipment, remain. Litigation ofThe trial in this matter could take many yearsis currently scheduled to resolve.begin in January 2015. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the Notices of Violation are meritorious. Ameren Missourimeritorious and will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.
Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren and Ameren Missouri. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred.
Clean Water Act
In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under theplants. The proposed rule affected facilities would be required either to meetimpose standards for reducing the mortality limits forof aquatic lifeorganisms impinged on the plant's intake screens or to reduce intake velocity to a specified level. The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduceentrained through the plant's cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in June 2013, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle energy centers at Ameren Ameren Missouri and AER with cooling water systems are subject to this proposed
rule. The proposedEPA has agreed to finalize the rule did not mandate cooling towers at existing facilities, as other technology options potentially could meetin April 2014. When finalized the site-specific standards. Ameren, Ameren Missouri and AER are currently evaluating the proposedfinal rule and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers or extensive modifications to the cooling water systems at our energy centers.
In September 2009,April 2013, the EPA announced its planproposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The EPAEPA's proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If the rule is engaged in information collectionenacted as proposed, Ameren Missouri would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022. Ameren is reviewing the proposed rule and analysis activities in support of this rulemaking. It has indicated that itevaluating its potential impact on operations. The EPA expects to issue final guidelines in April 2014.
Ash Management
In May 2010, the EPA announced proposed new regulations regarding the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs, under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules when finalized. The EPA is expected to issue a proposedfinal rule in April 2013December 2014. Ameren Missouri is currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and to finalize the rule in May 2014. Weuse of the ash ponds should be altered. Ameren Missouri is evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are unable at this time to predict the impact of this development.adopted.
Remediation
We are involved in a number of remediation actions to clean up sites impacted by hazardous waste sitessubstances 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. Ameren Missouri and Ameren Illinois have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by our rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for remediation costs associated with pre-existing environmental contamination at the transferred sites.
As of December 31, 2012,2013, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These sites are in various stages of investigation, evaluation, remediation, and closure. Based on current estimated plans, Ameren and Ameren Illinois could substantially conclude remediation efforts at
most of these sites by 2018. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its 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, 2012,2013, Ameren Missouri has one remaining former MGP site for which remediation is scheduled. Remediation is complete at the other Ameren Missouri former MGP sites. Ameren Missouri does not currently have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with MGP sites from utility customers.sites.
The following table presents, as of December 31, 20122013, the estimated probable obligation to remediatecomplete the remediation of these former MGP sites.
| | | | Estimate | | Recorded Liability(a) | Estimate | | Recorded Liability(a) |
| | Low | | High | | Low | | High | |
| Ameren | $ | 257 |
| | $ | 339 |
| | $ | 257 |
| $ | 278 |
| | $ | 338 |
| | $ | 278 |
|
| Ameren Missouri | 5 |
| | 6 |
| | 5 |
| 4 |
| | 5 |
| | 4 |
|
| Ameren Illinois | 252 |
| | 333 |
| | 252 |
| 274 |
| | 333 |
| | 274 |
|
| |
| (a) | Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate. |
The scope and extent to which these former MGP sites are remediated has increasedmay increase as remediation efforts continue. Considerable uncertainty remains in these estimates, as many factors can influence the ultimate actual costs, including site specific unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances and site accessibility. The actual costs may vary substantially from these estimates.
Ameren Illinois utilizedused an off-site landfill, which Ameren Illinois did not own, in connection with itsthe former operation of the Coffeenan energy center. While not currently mandated, Ameren Illinois maycould be required to perform certain remediationmaintenance activities associated with that landfill. As of December 31, 2012,2013, Ameren Illinois estimated the obligation related to the cleanupthis site at $0.5 million to
$6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill,some underground storage tanks and a water treatment plant in Illinois. As of December 31, 2012,2013, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.
Ameren Missouri has responsibility for the investigationis investigating and potential cleanup ofaddressing two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. While Ameren Missouri is the current owner of the site, but Ameren Missouriit did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of December 31, 2012,
2013, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the investigation and cleanup of this site, which was completed in 2005. Ameren Missouri anticipates that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup, and therefore, Ameren Missouri believes it therefore has no recorded liability at December 31, 2012,2013, for this site.
Ameren Missouri also has a federal agency mandate to complete an investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri 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, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri joined with other PRPspotentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.
The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted toIn December 2013, the EPA and aissued its record of decision is expected in 2013. Onceapproving the investigation and the remediation alternatives recommended by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementation of the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2.approved cleanup remedies. As of December 31, 2012,2013, Ameren Missouri estimated its obligation related to Sauget Area 2 at $0.3 million to $10 million. Ameren Missouri recorded a liability of $0.3 million to represent its estimated minimum obligation, as no other amount within the
range was a better estimate.
In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri owned substation in St. Charles, Missouri. As of December 31, 2012,2013, Ameren Missouri estimated the obligation related to the cleanup at $1.51.6 million to $2.34.5 million. Ameren Missouri recorded a liability of $1.51.6 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.
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 laws. We are unable to determine whether such practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity.
Ash Management
There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and AER are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and AER also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper
reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.
Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As
of December 31, 2012,2013, Ameren Missouri had an insurance receivable balance of $68 million. Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if its remaining liability insurance claims are not paid by insurers.
In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In January 2011, the district court ruled that the parties must first pursue alternative dispute resolution underand enforced the termsforum selection clause of their coverage agreement. The forum selection clause requires use of New York law and effectively requires mandatory arbitration. Ameren Missouri appealed the January 2011 ruling to the United States Court of Appeals for the Eighth Circuit. In August 2012, the court of appeals remanded the case to the district court for consideration of whether Missouri lawpublic policy voids the alternative dispute resolution provision offorum selection clause. In September 2013, the insurance policy.district court ruled that Missouri public policy does void the forum selection clause.
Separately, in April 2012, Ameren Missouri sued a second insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, which is pending in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. InThe insurance company filed a November 2012 ruling, the United States District Court for the Eastern District of Missouri denied the insurer's motion to require arbitration. The insurer filed an appeal incompel arbitration, which the district court denied. In April 2013, the United States Court of Appeals for the Eighth Circuit.Circuit affirmed the district court’s denial of the insurer’s motion and remanded the case to the district court.
Ameren's and Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if Ameren Missouri's remaining liability insurance claims are not paid by insurers.
Asbestos-related Litigation
Ameren, Ameren Missouri and Ameren Illinois have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure.exposure at our present or former energy centers. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many asthe average number of parties being 27282 parties named in some pending cases and as few as two in others. In the cases pending as of December 31, 2012, the average number of parties was 792013.
The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs’ activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a part of the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, for liabilities associated with asbestos-related claims and environmental conditions arising or existing from activities prior to the transfer. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.
In connection with the divestiture of New AER to IPH, certain agreements related to former Ameren Illinois energy centers were amended to provide that Ameren Illinois will continue to retain
asbestos exposure-related liabilities for claims arising or existing from activities prior to its transfer of the ownership of the former Ameren Illinois energy centers to New AER. IPH will be responsible for any asbestos-related claims arising from activities that occur after the effective date of the divestiture. No claims arose solely from activities in the period after the transfer of the energy centers from Ameren Illinois to AER, but before IPH took ownership of New AER.
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31, 20122013:
| | | Ameren | | Ameren Missouri | | Ameren Illinois | | Total(a) | | Ameren Missouri | | Ameren Illinois | | Total(a) |
| 4 | | 74 | | 96 | | 121 | |
| 1 | | | 47 | | 50 | | 71 |
| |
| (a) | Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants. |
At December 31, 20122013, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $11 million, $23 million, $95 million, and $146 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.
Ameren Illinois has a tariff rider to recover the costs of IP asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At December 31, 20122013, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP’s historical service territory. Similarly, theThe rider will permit recovery only from customers within IP’s historical service territory.
Ameren Illinois Municipal Taxes
Ameren Illinois received tax liability notices from the city of O'Fallon, Illinois, relating to prior-period electric and natural gas municipal taxes. The city alleges that Ameren Illinois failed to collect prior-period taxes from more than 2,1002,400 local resident addressesaccounts, primarily innewly annexed areas, for the period 20052004 through 2010.2012. In July 2013, the O’Fallon city administrator issued an order stating that Ameren Illinois is challengingwas liable to the city's position on this matter.city of O’Fallon for $4 million. In August 2013, Ameren Illinois filed an appeal and a stay of the O’Fallon city administrator’s order to the St. Clair County Circuit Court. In addition, in December 2012, the city of Peoria issued a tax liability notice alleging that Ameren Illinois failed to collect prior-period municipal taxes from certain accounts. In September 2013, a hearing officer issued an order stating that Ameren Illinois was liable to the city of Peoria for $0.5 million. Ameren Illinois filed an appeal and a stay of the order to the Peoria County Circuit Court. Ameren Illinois believes its defenses to the notices of tax liabilityallegations are meritorious and will defend itself vigorously. As of December 31, 2012,2013, Ameren Illinois did not believe it was probable thatestimated its obligation at $1 million to $5 million. Ameren Illinois recorded a liability of $1 million to represent its estimated minimum obligation to the city of O'Fallon would prevail and therefore has not recorded a charge to earnings for a loss contingency related
to this matter. Should Ameren Illinois ultimately be found liable for these prior-period municipal taxes,O'Fallon and the city of Peoria, as no other amount is estimated between $2 million and $4 million, including interest and penalties. within the range was a better estimate.
In addition, at the end of 2012, the city of O'Fallon and sixfive other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain local resident addresses.accounts. At this time, it is too earlypremature in Ameren Illinois' review of the additional notices received at the end of 2012 to reasonably estimate any likelihood of loss.
NOTE 16 – DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS
Illinois SalesTransaction Agreement with IPH
On December 2, 2013, Ameren completed the divestiture of New AER to IPH, in accordance with the transaction agreement between Ameren and Use Tax ExemptionsIPH dated March 14, 2013, as amended by a letter agreement entered into by Ameren and Credits
In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposesIPH on December 2, 2013. IPH acquired all of the Illinois income tax investment credit. In March 2010,outstanding limited liability interests in New AER, which was a newly created, wholly owned subsidiary of AER. Prior to the United States Supreme Court refused to hear an appealclosing, AER effected a reorganization that, among other things, transferred substantially all of the case, and the decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon casethat electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. EEI is challenging the state of Illinois' position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. Ameren does not believe that it is probable that the state of Illinois will prevail and therefore has not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren claimed manufacturing exemptions and credits of $27 million, which represents the maximum potential tax liability to Ameren, excluding any penalties assessed or interest accrued.
Genco, including EEI, and AERG did not claim any additional manufacturing exemptions or credits in 2012 and do not anticipate claiming any additional manufacturing exemptions or credits in 2013, pending discussions with the Illinois Department of Revenue. Each company, however, is reserving the right to apply for applicable refunds at a later date.
NOTE 16 - 2010 CORPORATE REORGANIZATION
On October 1, 2010, after receiving all necessary approvals, Ameren, CIPS, CILCO, IP, AERG and AER completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP ended. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren (the AERG distribution) and the subsequent contribution by Ameren of the AERG stock to AER. The Ameren Illinois Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting
guidance,its assets and liabilities transferred between entities under common control were accountedto New AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for atcertain intercompany balances discussed below; (ii) the historical cost basisassets and liabilities associated with Genco’s Meredosia and Hutsonville energy centers; (iii) the obligations relating to Ameren's single-employer pension and postretirement benefit plans; and (iv) the deferred income tax assets and liabilities associated with Ameren's ownership of these retained assets and liabilities.
Ameren retained certain pension and postretirement benefit obligations associated with current and former employees of AER, with the exception of the common parent,pension and postretirement benefit obligations associated with current and former employees of EEI, which were assumed by IPH. Ameren retained the Meredosia and Hutsonville energy centers, including their AROs, which totaled $31 million as ifof December 31, 2013. These energy centers were abandoned and had an immaterial property and plant asset balance as of December 31, 2013. All other AROs associated with AER were assumed by New AER or by Rockland Capital, the transfer had occurred at the beginningthird-party buyer of the earliest reporting period presented. Ameren's historical cost basis in Ameren Illinois included purchase accounting adjustments related to Ameren's acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distributionGrand Tower energy center, as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG's carrying value.discussed below.
Upon the IPH transaction agreement closing, all intercompany agreements and debt that existed between New AER and its subsidiaries, on the one hand, and Ameren and its non-New AER affiliates, on the other hand, with the exception of certain agreements, such as supply obligations to Ameren Illinois, Merger,a note from Marketing Company to Ameren relating to cash collateral that remained outstanding at closing, Genco money pool advances and certain New AER subsidiary money pool borrowings, were either retained or cancelled by Ameren, without any cost or obligation to IPH or New AER and its subsidiaries. Immediately prior to the debt and other obligationsclosing of CILCO and IP under their mortgage indentures, seniorthe divestiture, the money pool borrowings through which Ameren provided cash collateral to Marketing Company were converted to a note indentures, and pollution control bond agreementspayable to Ameren, which is payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. The
became debtbalance of the note was $18 million at December 31, 2013, and obligations of Ameren Illinois. The property owned by CILCO and IP immediately before the Ameren Illinois Merger that was subjectis reflected on Ameren's consolidated balance sheet in "Other assets."
Pursuant 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 securedtransaction agreement, as amended by the mortgage bonds held by their respective senior note trustee, subjectDecember 2, 2013 letter agreement, Ameren caused $235 million of cash to the release and other provisions of the respective senior note indenture. The debt and other obligations of CIPS remained debt and obligations of Ameren Illinois. Ameren Illinois secured the senior notes issued by CIPS with the benefit of a lien under the IP mortgage indenture. Ameren Illinois has also encumbered substantially all of the real estate, fixtures and equipment owned by CIPS immediately before the Ameren Illinois Merger with the lien of the IP mortgage indenture.
At the time of the Ameren Illinois Merger, the common stock of CILCO and IP, all wholly owned by Ameren, was canceled without consideration. Then, pursuant to the merger agreement: (1) every two shares of each series of IP preferred stock outstandingbe retained at New AER immediately prior to closing, which included amounts previously paid to Genco for the sale of the Elgin, Gibson City, and Grand Tower energy centers to Medina Valley as well as additional amounts retained at Genco, AERG, and Marketing Company. Within 120 days after the closing of the divestiture, a working capital adjustment will be finalized, which may result in a cash payment from Ameren Illinois Merger were automatically converted into one shareto IPH or from IPH to Ameren. Ameren received no cash proceeds as a result of a newly created seriesthe divestiture of Ameren Illinois preferred stock having the same payment and redemption terms as the existing series of IP preferred stock, exceptNew AER. Pursuant to the extent that IP preferred stockholders exercised their dissenters’ rightstransaction agreement, as amended, Ameren is obligated to pay up to $39 million for certain contingent liabilities. Of these liabilities, $29 million are included in accordance with Illinois law;"Other deferred credits and (2) each outstanding share of CIPS commonliabilities" and preferred stock remained outstanding, except$10 million are included in "Accounts and wages payable" on Ameren's December 31, 2013 consolidated balance sheet.
As a condition to the extent that CIPS preferred stockholderstransaction agreement, Genco exercised their dissenters’ rights in accordancethe amended put option agreement for the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. In October 2013, Genco completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, receiving total payments of $137.5 million. The third-party sale of these energy centers to Rockland Capital was completed on January 31, 2014 and is discussed below.
Sale of Gas-fired Energy Centers
Prior to entry into the transaction agreement with IPH,
Illinois law. Stockholders holding approximately 8,337 sharesGenco entered into a put option agreement, as amended, with Medina Valley. This agreement gave Genco the option to sell to Medina Valley the Elgin, Gibson City, and 423 shares of CIPS and IP preferred stock, respectively, exercised their dissenters’ rights.
In its applicationGrand Tower gas-fired energy centers for the FERC orders approvingfair market value of the energy centers, as determined by three independent appraisers. Genco exercised its option, and in October 2013 completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley for $137.5 million, which was the fair value of the gas-fired energy centers as determined by the three independent appraisers.
The transaction agreement with IPH, as amended, provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold by Medina Valley and if Medina Valley receives additional proceeds from such sale, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the $137.5 million previously paid to Genco.
On January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital for a total purchase price of $168 million, before consideration of a net working capital adjustment. The agreement with Rockland Capital required $17 million of the purchase price to be held in escrow until the two-year anniversary of the closing of the sale to fund certain indemnity obligations, if any, of Medina Valley. The net working capital adjustment will be finalized within 120 days after the January 31, 2014 closing date. As a result, pending final resolution of the net working capital adjustment, taxes, and other expenses, Medina Valley expects to pay Genco any remaining portion of the escrow balance on January 31, 2016. Ameren Illinois Mergerwill not record a gain from its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers.
Discontinued Operations Presentation
As of March 14, 2013, Ameren determined that New AER and the AERG distribution, Ameren committed to maintain a minimum 30% equity capital structure at Ameren Illinois after the Ameren Illinois MergerElgin, Gibson City, and the AERG distribution.
Ameren Illinois determined that the operating results of AERGGrand Tower gas-fired energy centers qualified for discontinued operations presentation; therefore,presentation. In addition, effective December 2, 2013, coinciding with the completion of the divestiture of New AER to IPH, Ameren determined that the Meredosia and Hutsonville energy centers had been abandoned. Ameren is prohibited from operating these energy centers through December 31, 2020, as a provision of the Illinois segregated AERG’s operating resultsPollution Control Board's November 2013 order granting IPH a variance of the MPS. As a result, Ameren determined the Meredosia and presented them separatelyHutsonville energy centers qualified for discontinued operations presentation as of December 2, 2013.
New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been classified collectively in Ameren’s consolidated financial statements as discontinued operations for all periods presented prior to October 1, 2010, in this report. For Ameren’s financial statements, AERG’s results of operations remain classified as continuing operations.The disposal groups have been aggregated in the disclosures below. The following table summarizespresents the operating resultscomponents of Ameren Illinois’ former merchant generation subsidiary, AERG, classified as discontinued operations in Ameren Illinois’ statementsAmeren's consolidated statement of income for the year ended December 31, 2010:
|
| | | |
| Operating revenues | $ | 274 |
|
| Operating expenses | 201 |
|
| Operating income | 73 |
|
| Other income | 1 |
|
| Interest charges | 14 |
|
| Income taxes | 20 |
|
| Income from discontinued operations, net of tax | $ | 40 |
|
NOTE 17 - IMPAIRMENT AND OTHER CHARGES
The following table summarizes the pretax charges recognized(loss) for the years ended December 31, 2013, 2012 2011, and 2010:2011:
|
| | | | | | | | | | | | | | | |
| | Long-Lived Assets and Related Charges | | Goodwill | | Emission Allowances | | Total |
| 2012 | | | | | | | |
Ameren(a) | $ | 2,578 |
| | $ | — |
| | $ | — |
| | $ | 2,578 |
|
| 2011 | | | | | | | |
Ameren(a) | 123 |
| | — |
| | 2 |
| | 125 |
|
| Ameren Missouri | 89 |
| | — |
| | — |
| | 89 |
|
| 2010 | | | | | | | |
Ameren(a) | 101 |
| | 420 |
| | 68 |
| | 589 |
|
|
| | | | | | | | | | | |
| | Year ended |
| | 2013 | | 2012 | | 2011 |
| Operating revenues | $ | 1,037 |
| | $ | 1,047 |
| | $ | 1,358 |
|
| Operating expenses | (1,207 | ) | (a) | (3,474 | ) | (b) | (1,150 | ) |
| Operating income (loss) | (170 | ) | | (2,427 | ) | | 208 |
|
| Other income (loss) | (1 | ) | | — |
| | 1 |
|
| Interest charges | (39 | ) | | (56 | ) | | (64 | ) |
| Income (loss) before income taxes | (210 | ) | | (2,483 | ) | | 145 |
|
| Income tax (expense) benefit | (13 | ) | | 987 |
| | (56 | ) |
| Income (loss) from discontinued operations, net of taxes | $ | (223 | ) | | $ | (1,496 | ) | | $ | 89 |
|
| |
| (a) | Includes amounts for registranta $201 million pretax loss on disposal relating to the New AER divestiture. |
| |
| (b) | Includes a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value under held and nonregistrant subsidiaries.used accounting guidance. In addition, includes a noncash pretax asset impairment charge of $1.95 billion to reduce the carrying values of all the AER coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values, under held and used accounting guidance, as a result of the decision in December 2012 that Ameren intended to exit the Merchant Generation business. |
EachUpon completion of the above chargesdivestiture of New AER, Ameren finalized its loss on disposal. Ameren received no cash proceeds from IPH for the divestiture of New AER. Ameren recorded a pretax charge to earnings related to the New AER divestiture of $201 million for the year ended December 31, 2013. The loss was recorded in “Operating expenses” within the components of the discontinued operations statement of income (loss). The ultimate loss on disposal may differ as “Impairmenta result of the finalization of the working capital adjustment within 120 days of close.
In 2013, Ameren adjusted the accumulated deferred income taxes on its consolidated balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER. This change in basis resulted in a discontinued operations deferred tax expense of $99 million, which was partially offset by the expected tax benefits of $86 million related to the pretax loss from discontinued operations including the loss on disposal, during the year ended December 31, 2013. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon the resolution of tax matters under IRS audit, including the adoption of recently issued guidance from the IRS related to tangible property repairs and other charges,” withmatters. As a result, tax expense and benefits ultimately realized in discontinued operations may differ materially from those recorded as of December 31, 2013.
As the exceptionElgin, Gibson City, and Grand Tower gas-fired energy center disposal group continued to meet the discontinued operations criteria at December 31, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. In December 2012, Ameren Missouri statement of income where it was recorded as “Loss from regulatory disallowance.” Thea noncash long-lived asset impairment charges did not result in a violation of any Ameren or Ameren subsidiary debt covenants or counterparty agreements. Each of the charges is discussed below.
Long-lived Assets Impairments
The Ameren Companies evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate thatcharge to reduce the carrying value of such assets mayAER’s energy centers, including the Elgin, Gibson City, and Grand Tower gas-fired energy centers, to their estimated fair values under the accounting guidance for held and used assets. Ameren did not be recoverable. Whether anrecord any additional impairment has occurred is determined by comparing the estimated undiscounted cash flows attributablerelating to the assets withElgin, Gibson City, and Grand Tower energy centers for the year ended December 31, 2013. As discussed above, on January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital for a total purchase price of $168 million, before consideration of a net working capital adjustment. Ameren
will not recognize a gain from the third party sale to Rockland Capital for any value in excess of its $137.5 million carrying value for this disposal group since any excess amount that Medina Valley may receive, net of taxes and other expenses, over the carrying value, of the assets. If the carrying value exceeds the undiscounted cash
flows, the Ameren Companies recognize an impairment charge equalwill ultimately be paid to Genco pursuant to the amount oftransaction agreement with IPH.
Long-lived Asset Impairments
New AER and the carrying value of the assets that exceeds its estimated fair value.
Merchant Generation
Ameren's Merchant Generation segment has experienced decreasing earningsElgin, Gibson City, and cash flows from operating activities over the past few years, includingGrand Tower energy centers were impaired under held and used accounting guidance in 2012 as margins have declined
principally as a result of weaker power prices. In addition, environmental regulations have resultedand the Meredosia and Hutsonville energy centers were impaired under held and used accounting guidance in significant investment requirements over the same time frame. During this period, Ameren has increasingly focused on allocating its capital resources to those opportunities that it believes offer the most attractive risk-adjusted return potential,2011. The 2012 and specifically focused on growing earnings from its rate-regulated operations through investment under constructive regulatory frameworks. Ameren has sought to have its Merchant Generation segment fund its operations internally and not rely on financing from Ameren. In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren's analysis of the current and projected future financial condition of its Merchant Generation segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation segment's reliance on Ameren's financial support and shared services support.2011 impairments are discussed below.
Ameren's date and method of exit from the Merchant Generation business is currently uncertain. Exit strategies may include the sale of all or parts of the Merchant Generation business or the restructuring of all or a portion of Ameren's equity position in Genco. Once a plan of disposal is finalized, Ameren's implementation of that plan may result in long-lived asset impairments, disposal-related losses, contingencies, reduction of existing deferred tax assets, and other consequences that are currently unknown.
As a result of the December 2012 decision that Ameren intendsintended to, and it iswas probable that it will,would, exit the Merchant Generation segment before the end of the Merchant Generation long-lived assets' previously estimated useful lives, Ameren determined that estimated undiscounted cash flows during the period in which it expectsexpected to continue to own certain energy centers would be insufficient to recover the carrying value of those energy centers. Accordingly, Ameren recorded a noncash pretax impairment charge of $1.95$1.95 billion in the fourth quarter of 2012 to reduce the carrying values of all of the Merchant Generation's coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values. The estimated undiscounted cash flows of the Joppa coal-fired energy center exceeded its carrying value; therefore, the Joppa coal-fired energy center was unimpaired. The net book value of Ameren's Merchant Generation long-lived assets was $748 million as of December 31, 2012.
In early 2012, the observable market price for power for delivery in that year and in future years in the Midwest sharply declined below 2011 levels, primarily because of declining natural gas prices and the impact of the stay of the CSAPR. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012. The sharp decline in the market price of power in early 2012 and
the related impact on electric margins, as well as the deceleration of construction of Genco's Newton energy center scrubber project, caused Merchant GenerationAmeren to evaluate, during the first quarter of 2012, whether the carrying values of its coal-firedMerchant Generation coal-
fired energy centers were recoverable. The carrying value of AERG's Duck Creek energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash pretax asset impairment charge of $628$628 million to reduce the carrying value of that energy center to its estimated fair value during the first quarter of 2012.
In December 2011, Genco ceased operations ofat its Meredosia and Hutsonville energy centers. As a result, Ameren recorded a noncash pretax asset impairment charge of $26$26 million to reduce the carrying value of the Meredosia and Hutsonville energy centers to their estimated fair values and a $4$4 million impairment offor materials and supplies, and $4 million for severance costs. See Note 1 - Summary of Significant Accounting Policies for further information regarding severance costs.
During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused Ameren to evaluate if the carrying value of its Merchant Generation energy centers were recoverable. The Meredosia energy center's carrying value and Medina Valley energy center's carrying value exceeded their estimated undiscounted future cash flows. As a result, during 2010, Ameren recorded a noncash pretax asset impairment charges of $101 million to reduce the carrying value of the Meredosia and Medina Valley energy centers to their estimated fair value. In 2012, Ameren sold the Medina Valley energy center. See Note 1 - Summary of Significant Accounting Policies for additional information regarding that sale.supplies.
Key assumptions used in the determination of estimated undiscounted cash flows of Ameren’s Merchant Generation segment’sfor the 2012 and 2011 long-lived assets
tested for impairment under held and used accounting guidance discussed above included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and terminal year earnings multiples, were used to estimate the fair value of each energy center. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements. Impairment within
The following table presents the Merchant Generation business segment was assessedcarrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at the energy center level. December 31, 2013, and 2012: |
| | | | | | | |
| | December 31, 2013 | | December 31, 2012 |
| Assets of discontinued operations | | | |
| Cash and cash equivalents | $ | — |
| | $ | 25 |
|
| Accounts receivable and unbilled revenue | 5 |
| | 102 |
|
| Materials and supplies | 5 |
| | 135 |
|
| Mark-to-market derivative assets | — |
| | 102 |
|
| Property and plant, net | 142 |
| | 748 |
|
Accumulated deferred income taxes, net(a) | 13 |
| | 395 |
|
| Other assets | — |
| | 104 |
|
| Total assets of discontinued operations | $ | 165 |
| | $ | 1,611 |
|
| Liabilities of discontinued operations | | | |
| Accounts payable and other current obligations | $ | 5 |
| | $ | 141 |
|
| Mark-to-market derivative liabilities | — |
| | 63 |
|
| Long-term debt, net | — |
| | 824 |
|
Asset retirement obligations(b) | 40 |
| | 97 |
|
| Pension and other postretirement benefits | — |
| | 40 |
|
| Other liabilities | — |
| | 28 |
|
| Total liabilities of discontinued operations | $ | 45 |
| | $ | 1,193 |
|
Accumulated other comprehensive income (c) | $ | — |
| | $ | 19 |
|
Noncontrolling interest(d) | $ | — |
| | $ | 8 |
|
| |
(a) | The December 31, 2013 balance primarily consists of deferred income tax assets related to the abandoned Meredosia and Hutsonville energy centers. |
| |
| (b) | Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $31 million and $26 million at December 31, 2013, and 2012, respectively. |
| |
| (c) | Accumulated other comprehensive income related to discontinued operations included in “Accumulated other comprehensive loss” on Ameren’s December 31, 2012, consolidated balance sheet. This balance related to New AER assets and liabilities that were realized or removed from Ameren’s consolidated balance sheet either before or at the December 2, 2013 closing of the New AER divestiture. |
| |
| (d) | The 20% ownership interest of EEI not owned by Ameren was included in “Noncontrolling interests” on Ameren’s December 31, 2012, consolidated balance sheet. This noncontrolling interest was removed from Ameren’s consolidated balance sheet at the December 2, 2013 closing of the New AER divestiture. |
Ameren does not expect to incur material future cash expenditures ashas continuing transactions with New AER. Ameren Illinois has power supply agreements with Marketing Company, which are a result of the power procurement process in Illinois administered by the IPA, as required by the Illinois Public Utilities Act. Ameren Illinois continues to purchase power and to purchase trade receivables as required by Illinois law. Ameren Illinois and ATXI continue to sell transmission services to Marketing Company. Also, the transaction agreement requires Ameren (parent) to maintain certain guarantees discussed below. Immediately prior to the transaction agreement closing, the money pool borrowings through which Ameren provided cash
collateral to Marketing Company were converted to a note payable to Ameren, which is payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Also, within 120 days after closing, a working capital adjustment will be finalized, which may result in a cash payment from Ameren to New AER or from New AER to Ameren. Ameren has determined that the continuing cash flows generated by these impairments.arrangements are not significant and, accordingly, are not deemed to be direct cash flows of the divested business. Additionally, these arrangements do not provide Ameren with the ability to significantly influence the operating results of New AER.
Ameren Missouriwill not have significant continuing involvement with or material cash flows from the Elgin, Gibson City, or Grand Tower energy centers after their sale.
During 2011,Ameren Guarantees
Upon the MoPSC issued an electric rate orderdivestiture of New AER, the transaction agreement between Ameren and IPH requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture. Ameren must also provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation is secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing.
At December 31, 2013, Ameren had a total of $190 million in guarantees outstanding, which included:
$176 million related to guarantees supporting Marketing Company for physically and financially settled power transactions with its counterparties that disallowedwere in place at the recoveryDecember 2, 2013 closing of all coststhe divestiture, as well as for Marketing Company's clearing broker and other service agreements. If Marketing Company did not fulfill its
obligations to these counterparties who had active open positions as of enhancements, or costs thatDecember 31, 2013, Ameren would have been incurred absentrequired under its guarantees to provide $6 million to the breach,counterparties.
$14 million related to therequirements for leasing agreements and potential environmental obligations.
rebuildingAdditionally, at December 31, 2013, Ameren had issued letters of the Taum Sauk energy center in excesscredit totaling $11 million as credit support on behalf of the amount recovered from property insurance. Consequently, New AER.
Ameren and Ameren Missouri eachhas not recorded a pretax charge to earningsreserve for these contingent obligations because it does not believe a payment for any of $89 million.
Goodwill
We evaluate goodwill for impairmentthese guarantees is probable as of OctoberDecember 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 liabilities. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss equivalent to the difference is recorded as a reduction of goodwill and a charge to operating expense.
During the third quarter of 2010, we concluded that events had occurred and circumstances had changed which, when considered in the aggregate, indicated that it was more likely than not that the fair value of Ameren's Merchant Generation reporting unit was less than its carrying value. Such events and circumstances included the sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted. In July 2010, the EPA issued the proposed CSAPR. The proposed CSAPR, along with other pending regulations, was expected to result in a significant increase in capital and operations and maintenance expenditures for Ameren's Merchant Generation energy centers.
Ameren's Merchant Generation reporting unit failed step one of the 2010 interim impairment test, as the reporting unit's carrying value exceeded its estimated fair value. Therefore, in order to measure the goodwill impairment in step two, we estimated the implied fair value of Ameren's Merchant Generation goodwill. We determined that the implied fair value of goodwill was less than the carrying amount of goodwill, indicating that Ameren's Merchant Generation goodwill was impaired. Based on the results of step two of the impairment test, Ameren recorded a noncash impairment charge of $420 million, which represented all of the goodwill assigned to Ameren's Merchant Generation reporting unit.
The fair value estimate of Ameren's Merchant Generation reporting unit 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. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year cash flows, and observable industry market multiples. We used our best estimates in making these evaluations. We considered various factors, including forward price projections for energy and fuel costs, environmental compliance costs, and operating costs. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.
Intangible Assets
Prior to 2010, Ameren's Merchant Generation expected to use its SO2 emission allowances for ongoing operations. In July 2010, the EPA issued the proposed CSAPR, which would have restricted the use of existing SO2 emission allowances. As a result, Merchant Generation no longer expected all of its SO2 emission allowances would be used in operations. Therefore, during 2010, Ameren recorded a $68 million pretax impairment charge to reduce the carrying value of Merchant Generation's SO2 emission allowances to their estimated fair value.
In July 2011, the EPA issued CSAPR, which created new allowances for SO2 and NOx emissions, and restricted the use of preexisting SO2 and NOx allowances to the acid rain program and to the NOx budget trading program, respectively. As a result, observable market prices for existing emission allowances declined materially. Consequently, Ameren recorded a noncash pretax impairment charge of $2 million relating to Merchant Generation's emission allowances. Ameren Missouri recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowance, which had no impact on earnings.
The fair value of the SO2 and NOx emission allowances was based on observable and unobservable inputs, which were classified as Level 3 inputs for fair value measurements.2013.
NOTE 18 -17 – SEGMENT INFORMATION
Ameren has threetwo reportable segments: Ameren Missouri and Ameren Illinois, and Merchant Generation.Illinois. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all the operations of Ameren Missouri’s business as described in Note 1 -– Summary of Significant Accounting Policies. The Ameren Illinois Segmentsegment for both Ameren and Ameren Illinois consists of all of the operations of Ameren Illinois as described in Note 1 -– Summary of Significant Accounting Policies. The Merchant Generation segment for Ameren consists primarily of the operations or activities of AER, including Genco, EEI, AERG, and Marketing Company. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. The Other category also includes certain corporate activities previously included in the Merchant Generation segment. See Note 16 – Divestiture Transactions and Discontinued Operations for additional information.
The following table presents information about the reported revenues and specified items reflected in Ameren’s net income attributable to Ameren Corporation from continuing operations for the years ended December 31, 2013, 2012 2011,, and 2010,2011, and total assets in continuing operations as of December 31, 20122013, 20112012, and 20102011.
Ameren
|
| | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois | | Other | | Intersegment Eliminations | | Consolidated | |
| 2013 | | | | | | | | | | |
| External revenues | $ | 3,516 |
| | $ | 2,307 |
| | $ | 15 |
| | $ | — |
| | $ | 5,838 |
| |
| Intersegment revenues | 25 |
| | 4 |
| | 2 |
| | (31 | ) | | — |
| |
| Depreciation and amortization | 454 |
| | 243 |
| | 9 |
| | — |
| | 706 |
| |
| Interest and dividend income | 27 |
| | 2 |
| | 1 |
| | — |
| | 30 |
| |
| Interest charges | 210 |
| | 143 |
| | 45 |
| | — |
| | 398 |
| |
| Income taxes (benefit) | 242 |
| | 110 |
| | (41 | ) | | — |
| | 311 |
| |
| Net income (loss) attributable to Ameren Corporation from continuing operations | 395 |
| | 160 |
| | (43 | ) | | — |
| | 512 |
| |
| Capital expenditures | 648 |
| | 701 |
| | 30 |
| (a) | — |
| | 1,379 |
| |
| Total assets | 12,904 |
| | 7,454 |
| | 752 |
| | (233 | ) | | 20,877 |
| (b) |
| 2012 | | | | | | | | | | |
| External revenues | $ | 3,252 |
| | $ | 2,524 |
| | $ | 5 |
| | $ | — |
| | $ | 5,781 |
| |
| Intersegment revenues | 20 |
| | 1 |
| | 3 |
| | (24 | ) | | — |
| |
| Depreciation and amortization | 440 |
| | 221 |
| | 12 |
| | — |
| | 673 |
| |
| Interest and dividend income | 32 |
| | — |
| | — |
| | — |
| | 32 |
| |
| Interest charges | 223 |
| | 129 |
| | 40 |
| | — |
| | 392 |
| |
| Income taxes (benefit) | 252 |
| | 94 |
| | (39 | ) | | — |
| | 307 |
| |
| Net income (loss) attributable to Ameren Corporation from continuing operations | 416 |
| | 141 |
| | (41 | ) | | — |
| | 516 |
| |
| Capital expenditures | 595 |
| | 442 |
| | 26 |
| (a) | — |
| | 1,063 |
| |
| Total assets | 13,043 |
| | 7,282 |
| | 1,228 |
| | (934 | ) | | 20,619 |
| (b) |
| 2011 | | | | | | | | | | |
| External revenues | $ | 3,360 |
| | $ | 2,784 |
| | $ | 4 |
| | $ | — |
| | $ | 6,148 |
| |
| Intersegment revenues | 23 |
| | 3 |
| | 3 |
| | (29 | ) | | — |
| |
| Depreciation and amortization | 408 |
| | 215 |
| | 20 |
| | — |
| | 643 |
| |
| Interest and dividend income | 30 |
| | 1 |
| | — |
| | — |
| | 31 |
| |
| Interest charges | 209 |
| | 136 |
| | 42 |
| | — |
| | 387 |
| |
| Income taxes (benefit) | 161 |
| | 127 |
| | (34 | ) | | — |
| | 254 |
| |
| Net income (loss) attributable to Ameren Corporation from continuing operations | 287 |
| | 193 |
| | (49 | ) | | — |
| | 431 |
| |
| Capital expenditures | 550 |
| | 351 |
| | (20 | ) | (a) | — |
| | 881 |
| |
| Total assets | 12,757 |
| | 7,213 |
| | 1,211 |
| | (1,179 | ) | | 20,002 |
| (b) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Ameren Missouri | | Ameren Illinois Segment | | Merchant Generation | | Other | | Intersegment Eliminations | | Consolidated |
| 2012 | | | | | | | | | | | |
| External revenues | $ | 3,251 |
| | $ | 2,509 |
| | $ | 1,063 |
| | $ | 5 |
| | $ | — |
| | $ | 6,828 |
|
| Intersegment revenues | 21 |
| | 16 |
| | 310 |
| | 4 |
| | (351 | ) | | — |
|
| Depreciation and amortization | 440 |
| | 221 |
| | 102 |
| | 12 |
| | — |
| | 775 |
|
| Interest and dividend income | 32 |
| | — |
| | — |
| | 40 |
| | (39 | ) | | 33 |
|
| Interest charges | 223 |
| | 129 |
| | 95 |
| | 38 |
| | (37 | ) | | 448 |
|
| Income taxes (benefit) | 252 |
| | 94 |
| | (1,019 | ) | | (7 | ) | | — |
| | (680 | ) |
Net income (loss) attributable to Ameren Corporation(a) | 416 |
| | 141 |
| | (1,516 | ) | (b) | (15 | ) | | — |
| | (974 | ) |
| Capital expenditures | 595 |
| | 442 |
| | 178 |
| | 25 |
|
| — |
| | 1,240 |
|
| Total assets | 13,043 |
| | 7,282 |
| | 1,300 |
| | 1,228 |
| | (1,018 | ) | | 21,835 |
|
| 2011 | | | | | | | | | | | |
| External revenues | $ | 3,358 |
| | $ | 2,774 |
| | $ | 1,394 |
| | $ | 5 |
| | $ | — |
| | $ | 7,531 |
|
| Intersegment revenues | 25 |
| | 13 |
| | 235 |
| | 4 |
| | (277 | ) | | — |
|
| Depreciation and amortization | 408 |
| | 215 |
| | 143 |
| | 19 |
| | — |
| | 785 |
|
| Interest and dividend income | 30 |
| | 1 |
| | — |
| | 44 |
| | (43 | ) | | 32 |
|
| Interest charges | 209 |
| | 136 |
| | 105 |
| | 44 |
| | (43 | ) | | 451 |
|
| Income taxes (benefit) | 161 |
| | 127 |
| | 32 |
| | (10 | ) | | — |
| | 310 |
|
Net income (loss) attributable to Ameren Corporation(a) | 287 |
| | 193 |
| | 45 |
|
| (6 | ) | | — |
| | 519 |
|
| Capital expenditures | 550 |
| | 351 |
| | 153 |
| | (24 | ) | (c) | — |
| | 1,030 |
|
| Total assets | 12,757 |
| | 7,213 |
| | 3,833 |
| | 1,211 |
| | (1,369 | ) | | 23,645 |
|
| 2010 | | | | | | | | | | | |
| External revenues | $ | 3,176 |
| | $ | 3,002 |
| | $ | 1,459 |
| | $ | 1 |
| | $ | — |
| | $ | 7,638 |
|
| Intersegment revenues | 21 |
| | 12 |
| | 234 |
| | 13 |
| | (280 | ) | | — |
|
| Depreciation and amortization | 382 |
| | 210 |
| | 146 |
| | 27 |
| | — |
| | 765 |
|
| Interest and dividend income | 31 |
| | 1 |
| | 1 |
| | 25 |
| | (25 | ) | | 33 |
|
| Interest charges | 213 |
| | 143 |
| | 133 |
| | 35 |
| | (27 | ) | | 497 |
|
| Income taxes (benefit) | 199 |
| | 137 |
| | 6 |
| | (17 | ) | | — |
| | 325 |
|
Net income (loss) attributable to Ameren Corporation(a) | 364 |
| | 208 |
| | (409 | ) | (b) | (24 | ) | | — |
| | 139 |
|
| Capital expenditures | 624 |
| | 281 |
| | 101 |
| | 36 |
| | — |
| | 1,042 |
|
| Total assets | 12,504 |
| | 7,406 |
| | 3,934 |
| | 1,354 |
| | (1,687 | ) | | 23,511 |
|
| |
| (a) | Represents net income (loss) available to common stockholders.Includes the elimination of intercompany transfers. |
| |
| (b) | Includes noncash impairmentExcludes total assets from discontinued operations of $165 million, $1,611 million, and other charges, which were $2,5783,721 million as of December 31, 2013, 2012, and $589 million2011 before tax, recognized during the years ended December 31, 2012, and 2010,, respectively. See Note 17 - Impairment and Other Charges for additional information.
|
| |
(c) | Includes the elimination of intercompany transfers. |
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
|
| | | | | | | | | | | | | | | | |
Quarter Ended(a) | | Operating Revenues | | Operating Income (Loss)(b) | | Net Income (Loss) Attributable to Ameren Corporation | | Earnings (Loss) per
Common
Share - Basic and
Diluted |
| Ameren | | | | | | | | |
| March 31, 2012 | | $ | 1,658 |
| | $ | (422 | ) | | $ | (403 | ) | | $ | (1.66 | ) |
| March 31, 2011 | | 1,904 |
| | 227 |
| | 71 |
| | 0.29 |
|
| June 30, 2012 | | 1,660 |
| | 363 |
| | 211 |
| | 0.87 |
|
| June 30, 2011 | | 1,781 |
| | 316 |
| | 138 |
| | 0.57 |
|
| September 30, 2012 | | 2,001 |
| | 635 |
| | 374 |
| | 1.54 |
|
| September 30, 2011 | | 2,268 |
| | 550 |
| | 285 |
| | 1.18 |
|
| December 31, 2012 | | 1,509 |
| | (1,816 | ) | | (1,156 | ) | | (4.76 | ) |
| December 31, 2011 | | 1,578 |
| | 148 |
| | 25 |
| | 0.10 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Ameren | 2013 | | | 2012 |
Quarter ended (a) | March 31 | | June 30 | | September 30 | | December 31 | | | March 31 | | June 30 | | September 30 | | December 31 |
| Operating revenues | $ | 1,475 |
| | $ | 1,403 |
| | $ | 1,638 |
| | $ | 1,322 |
| | | $ | 1,412 |
| | $ | 1,402 |
| | $ | 1,709 |
| | $ | 1,258 |
|
| Operating income | 185 |
| | 261 |
| | 567 |
| | 171 |
| | | 159 |
| | 347 |
| | 570 |
| | 112 |
|
Net income (loss)(b) | (143 | ) | | 96 |
| | 304 |
| | 38 |
| | | (403 | ) | | 210 |
| | 374 |
| | (1,155 | ) |
| Net income attributable to Ameren Corporation – continuing operations | $ | 54 |
| | $ | 105 |
| | $ | 305 |
| | $ | 48 |
| | | $ | 38 |
| | $ | 164 |
| | $ | 302 |
| | $ | 12 |
|
Net income (loss) attributable to Ameren Corporation – discontinued operations (b) | (199 | ) | | (10 | ) | | (3 | ) | | (11 | ) | | | (441 | ) | | 47 |
| | 72 |
| | (1,168 | ) |
| Net income (loss) attributable to Ameren Corporation | $ | (145 | ) | | $ | 95 |
| | $ | 302 |
| | $ | 37 |
| | | $ | (403 | ) | | $ | 211 |
| | $ | 374 |
| | $ | (1,156 | ) |
| Earnings per common share – basic – continuing operations | $ | 0.22 |
| | $ | 0.44 |
| | $ | 1.26 |
| | $ | 0.19 |
| | | $ | 0.16 |
| | $ | 0.67 |
| | $ | 1.25 |
| | $ | 0.05 |
|
| Earnings (loss) per common share – basic – discontinued operations | (0.82 | ) | | (0.05 | ) | | (0.01 | ) | | (0.04 | ) | | | (1.82 | ) | | 0.20 |
| | 0.29 |
| | (4.81 | ) |
| Earnings (loss) per common share – basic | $ | (0.60 | ) | | $ | 0.39 |
| | $ | 1.25 |
| | $ | 0.15 |
| | | $ | (1.66 | ) | | $ | 0.87 |
| | $ | 1.54 |
| | $ | (4.76 | ) |
| Earnings per common share – diluted – continuing operations | $ | 0.22 |
| | $ | 0.44 |
| | $ | 1.25 |
| | $ | 0.19 |
| | | $ | 0.16 |
| | $ | 0.67 |
| | $ | 1.25 |
| | $ | 0.05 |
|
| Earnings (loss) per common share – diluted – discontinued operations | (0.82 | ) | | (0.05 | ) | | (0.01 | ) | | (0.04 | ) | | | (1.82 | ) | | 0.20 |
| | 0.29 |
| | (4.81 | ) |
| Earnings (loss) per common share – diluted | $ | (0.60 | ) | | $ | 0.39 |
| | $ | 1.24 |
| | $ | 0.15 |
| | | $ | (1.66 | ) | | $ | 0.87 |
| | $ | 1.54 |
| | $ | (4.76 | ) |
| |
(a) | The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding and to changes in the number of weighted-average shares outstanding each period. |
| |
(b) | Includes pretax "Impairment and other charges"asset impairment charge of $2,578 million and $125 million$2.6 billion recorded at Amerenin discontinued operations during the yearsyear ended December 31, 2012, and 2011, respectively.2012. See Note 17 - Impairment16 – Divestiture Transactions and Other ChargesDiscontinued Operations under Part II, Item 8, for additional information. |
|
| | | | | | | | | | | | | | | | |
| Quarter Ended | | Operating Revenues | | Operating Income | | Net Income (Loss) | | Net Income (Loss) Available to Common Stockholder |
| Ameren Missouri | | | | | | | | |
| March 31, 2012 | | $ | 691 |
| | $ | 78 |
| | $ | 22 |
| | $ | 21 |
|
| March 31, 2011 | | 772 |
| | 77 |
| | 22 |
| | 21 |
|
| June 30, 2012 | | 844 |
| | 269 |
| | 144 |
| | 143 |
|
| June 30, 2011 | | 822 |
| | 176 |
| | 91 |
| | 90 |
|
| September 30, 2012 | | 1,064 |
| | 429 |
| | 237 |
| | 236 |
|
| September 30, 2011 | | 1,115 |
| | 333 |
| | 191 |
| | 190 |
|
| December 31, 2012 | | 673 |
| | 69 |
| | 16 |
| | 16 |
|
| December 31, 2011 | | 674 |
| | 23 |
| | (14 | ) | | (14 | ) |
|
| | | | | | | | | | | | | | | | |
| Ameren Missouri Quarter ended | | Operating revenues | | Operating income | | Net income (loss) | | Net income (loss) available to common stockholder |
| March 31, 2013 | | $ | 796 |
| | $ | 111 |
| | $ | 41 |
| | $ | 40 |
|
| March 31, 2012 | | 691 |
| | 78 |
| | 22 |
| | 21 |
|
| June 30, 2013 | | 889 |
| | 179 |
| | 85 |
| | 84 |
|
| June 30, 2012 | | 844 |
| | 269 |
| | 144 |
| | 143 |
|
| September 30, 2013 | | 1,093 |
| | 417 |
| | 239 |
| | 238 |
|
| September 30, 2012 | | 1,064 |
| | 429 |
| | 237 |
| | 236 |
|
| December 31, 2013 | | 763 |
| | 96 |
| | 33 |
| | 33 |
|
| December 31, 2012 | | 673 |
| | 69 |
| | 16 |
| | 16 |
|
|
| | | | | | | | | | | | | | | | |
| Quarter Ended | | Operating Revenues | | Operating Income | | Net Income | | Net Income Available to Common Stockholder |
| Ameren Illinois | | | | | | | | |
| March 31, 2012 | | $ | 724 |
| | $ | 89 |
| | $ | 28 |
| | $ | 27 |
|
| March 31, 2011 | | 808 |
| | 88 |
| | 34 |
| | 33 |
|
| June 30, 2012 | | 564 |
| | 86 |
| | 33 |
| | 32 |
|
| June 30, 2011 | | 623 |
| | 99 |
| | 38 |
| | 37 |
|
| September 30, 2012 | | 648 |
| | 151 |
| | 71 |
| | 71 |
|
| September 30, 2011 | | 745 |
| | 196 |
| | 98 |
| | 98 |
|
| December 31, 2012 | | 589 |
| | 51 |
| | 12 |
| | 11 |
|
| December 31, 2011 | | 611 |
| | 75 |
| | 26 |
| | 25 |
|
During preparation of the 2012 annual statements of cash flows, errors were identified in Ameren's and Ameren Missouri's 2012 interim statements of cash flows. The errors, which were $14 million, $26 million, and $49 million through the year-to-date first, second, and third quarters of 2012, respectively, are not considered material. The errors related to the classification of certain activity from the nuclear decommissioning trust fund and increased operating cash flows and reduced investing cash flows for each of these year-to-date periods. The 2012 interim statements of cash flows will be revised to correct for these errors in the Ameren and Ameren Missouri 2013 Form 10-Q filings. |
| | | | | | | | | | | | | | | | |
| Ameren Illinois Quarter ended | | Operating revenues | | Operating income | | Net income | | Net income available to common stockholder |
| March 31, 2013 | | $ | 684 |
| | $ | 85 |
| | $ | 32 |
| | $ | 31 |
|
| March 31, 2012 | | 724 |
| | 89 |
| | 28 |
| | 27 |
|
| June 30, 2013 | | 516 |
| | 87 |
| | 32 |
| | 31 |
|
| June 30, 2012 | | 564 |
| | 86 |
| | 33 |
| | 32 |
|
| September 30, 2013 | | 547 |
| | 158 |
| | 77 |
| | 77 |
|
| September 30, 2012 | | 648 |
| | 151 |
| | 71 |
| | 71 |
|
| December 31, 2013 | | 564 |
| | 85 |
| | 22 |
| | 21 |
|
| December 31, 2012 | | 589 |
| | 51 |
| | 12 |
| | 11 |
|
| |
| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. |
None.
| |
| ITEM 9A. | CONTROLS AND PROCEDURES. |
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 20122013 fiscal year.
| |
| (a) | Evaluation of Disclosure Controls and Procedures |
As of December 31, 2012,2013, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based on those evaluations, as of December 31, 2012,2013, the principal executive officer and principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.
| |
| (b) | Management’s Report on Internal Control over Financial Reporting |
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 in Internal Control -– Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(COSO 1992). After making that evaluation, management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of December 31, 2012.2013. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2012,2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an attestation report of Ameren Missouri’s or Ameren Illinois’ (the Subsidiary Registrants) independent registered public accounting firm regarding internal control over financial reporting. Management’s report for each of the Subsidiary Registrants is not subject to attestation by thean independent registered public accounting firm.
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.
| |
| (c) | Change in Internal Control |
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.
| |
| ITEM 9B. | OTHER INFORMATION. |
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 20122013 that has not previously been reported on an SEC Form 8-K.
PART III
| |
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE. |
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 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14A; such informationit is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14C; such informationit is incorporated herein by reference. Specifically, reference is made to the following
sections of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Information Concerning Nominees to the Board of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance” and “Board Structure.”
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.
Ameren Missouri and Ameren Illinois do not have separately designated standing audit committees, but instead use Ameren’s audit and risk committee to perform such committee functions for
their boards of directors. These companies have no securities listed on the NYSE and therefore are not subject to the NYSE listing standards. Walter J. Galvin serves as chairman of Ameren’s audit and risk committee, and Stephen F. Brauer, Catherine S. Brune, and Ellen M. Fitzsimmons and Stephen R. Wilson serve as members. The board of directors of Ameren has determined that Walter J. Galvin qualifies as an audit committee financial expert and that he is “independent” as that term is used in SEC Regulation 14A.
Also, on the same basis as reported above, the boards of directors of Ameren Missouri and Ameren Illinois use the nominating and corporate governance committee of Ameren’s board of directors to perform such committee functions. This committee is responsible for the nomination of directors and
corporate governance practices. Ameren’s nominating and corporate governance committee will consider director nominations from stockholdersshareholders in accordance with its Policy Regarding Nominations of Directors, which can be found on Ameren’s website: www.ameren.com.
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 controller, and the treasurer of each of the Ameren Companies. Ameren has also adopted a Codecode of Business Conductbusiness conduct that applies to the
directors, officers, 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 website (www.ameren.com) the Code of Ethics and the Corporate Compliance Policy. Any amendment to the Code of Ethics or the Corporate Compliance Policy and any waiver from a provision of the Code of Ethics or the Corporate 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 website within four business days following the date of the amendment or waiver.
| |
| ITEM 11. | EXECUTIVE COMPENSATION. |
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 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Executive Compensation,”Compensation” and “Human Resources Committee Interlocks and Insider Participation.”
| |
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. |
Equity Compensation Plan Information
The following table presents information as of December 31, 2012,2013, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans.
| | Plan Category | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) | | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b) | | Number of Securities Remaining Available for Future Issuance Equity Compensation Plans (excluding securities reflected in column (a))(c) | | Column A Number of Securities To Be Issued Upon Exercise of Outstanding Options, Warrants and Rights | | Column B Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | | Column C Number of Securities Remaining Available for Future Issuance Equity Compensation Plans (excluding securities reflected in Column A) |
Equity compensation plans approved by security holders(a) | | 1,813,814 |
| | (b) |
| | 1,577,354 |
| | 2,509,073 |
| | (b) |
| | 627,648 |
|
| Equity compensation plans not approved by security holders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 1,813,814 |
| | (b) |
| | 1,577,354 |
| | 2,509,073 |
| | (b) |
| | 627,648 |
|
| |
| (a) | Consists of the Ameren Corporation 2006 Omnibus Incentive Compensation Plan, which was approved by shareholders in May 2006 and expires on May 2, 2016. Pursuant to grants of performance share units (PSUs) under the 2006 Omnibus Incentive Compensation Plan, 230,490801,853 of the securities represent PSUs that vested as of December 31, 20122013 (including accrued and reinvested dividends), and 1,538,2041,653,280 of the securities represent target PSUs granted but not vested (including accrued and reinvested dividends) as of December 31, 2012.2013. The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level depending upon the achievement of total shareholder return objectives established for such awards. For additional information about the PSUs, including payout calculations, see “Compensation Discussion and Analysis -– Long-Term Incentives: Performance Share Unit Program (PSUP)” in Ameren’s definitive proxy statement for its 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14A. 45,12053,940 of the securities represent shares that may be issued as of December 31, 2012,2013, to satisfy obligations under the Ameren Corporation Deferred Compensation Plan for members of the board of directors. |
| |
| (b) | Earned PSUs and deferred compensation stock units are paid in shares of Ameren common stock on a one-for-one basis. Accordingly, the PSUs and deferred compensation stock units have been excluded for purposes of calculating the weighted-average exercise price. |
Ameren Missouri and Ameren Illinois do not have separate equity compensation plans.
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 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Security Ownership.”
| |
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE. |
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 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by Item 404 and Item 407(a) ofthese SEC Regulation S-K items for Ameren Missouri and Ameren Illinois will be included in each company’s definitive information statement for its 20132014 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Specifically, reference is made to the following sections of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Policy and Procedures With Respect to Related Person Transactions” and “Director Independence.”
| |
| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES. |
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 Ameren Missouri and Ameren Illinois for their 20132014 annual meetings of stockholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference. Specifically, reference is made to the following section of Ameren’s definitive proxy statement and each of Ameren Missouri’s and Ameren Illinois’ definitive information statement: “Independent Registered Public Accounting Firm.”
PART IV
| |
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. |
|
| |
| | |
| (a)(1) Financial Statements | Page No. |
| Ameren | |
| Report of Independent Registered Public Accounting Firm | |
Consolidated Statement of Income (Loss) -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
| Consolidated Statement of Comprehensive Income (Loss) | |
Consolidated Balance Sheet -– December 31, 20122013 and 20112012 | |
Consolidated Statement of Cash Flows -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Consolidated Statement of Stockholders’ Equity -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Union Electric CompanyAmeren Missouri | |
| Report of Independent Registered Public Accounting Firm | |
Statement of Income and Comprehensive Income -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Balance Sheet -– December 31, 20122013 and 20112012 | |
Statement of Cash Flows -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Statement of Stockholders’ Equity -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
| Ameren Illinois | |
| Report of Independent Registered Public Accounting Firm | |
Consolidated Statement of Income and Comprehensive Income -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Balance Sheet -– December 31, 2013 and 2012 | |
| Statement of Cash Flows – Years Ended December 31, 2013, 2012, and 2011 | |
Consolidated Statement of Cash Flows -Stockholders’ Equity – Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Consolidated Statement of Stockholders’ Equity - Years Ended December 31, 2012, 2011, and 2010 | |
| (a)(2) Financial Statement Schedules | |
Schedule I -– Condensed Financial Information of Parent -– Ameren: | |
Condensed Statement of Income (Loss) and Comprehensive Income (Loss) -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Condensed Balance Sheet -– December 31, 20122013 and 20112012 | |
Condensed Statement of Cash Flows -– Years Ended December 31, 2013, 2012, 2011, and 20102011 | |
Schedule II -– Valuation and Qualifying Accounts for the years ended December 31, 2013, 2012, 2011, and 20102011 | |
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.
|
| | |
| | | |
| (a)(3) | | Exhibits. |
| | | Reference is made to the Exhibit Index commencing on page 181.169. |
| (b) | | Exhibits are listed in the Exhibit Index commencing on page 181.169. |
| | SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010 | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011 | | SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011 |
| (In millions) | 2012 | | 2011 | | 2010 | 2013 | | 2012 | | 2011 |
| Operating revenues | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
| Impairment and other charges | — |
| | — |
| | 372 |
| |
| Operating expenses | 22 |
| | 15 |
| | 24 |
| 26 |
| | 17 |
| | 13 |
|
| Operating loss | (22 | ) | | (15 | ) | | (396 | ) | (26 | ) | | (17 | ) | | (13 | ) |
| Equity in earnings (loss) of subsidiaries | (954 | ) | | 527 |
| | 535 |
| |
| Equity in earnings of subsidiaries | | 546 |
| | 546 |
| | 464 |
|
| Interest income from affiliates | 40 |
| | 44 |
| | 28 |
| 3 |
| | 3 |
| | 5 |
|
| Miscellaneous expense | 4 |
| | 4 |
| | 3 |
| 5 |
| | 4 |
| | 4 |
|
| Interest charges | 39 |
| | 41 |
| | 56 |
| 42 |
| | 39 |
| | 41 |
|
| Income tax (benefit) | (5 | ) | | (8 | ) | | (31 | ) | (36 | ) | | (27 | ) | | (20 | ) |
| Net income (loss) | (974 | ) | | 519 |
| | 139 |
| |
| Net Income Attributable to Ameren Corporation – Continuing Operations | | 512 |
| | 516 |
| | 431 |
|
| Net Income (Loss) Attributable to Ameren Corporation – Discontinued Operations | | (223 | ) | | (1,490 | ) | | 88 |
|
| Net Income (Loss) Attributable to Ameren Corporation | | $ | 289 |
| | $ | (974 | ) | | $ | 519 |
|
| | | | | | | |
| Net Income Attributable to Ameren Corporation – Continuing Operations | | $ | 512 |
| | $ | 516 |
| | $ | 431 |
|
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | |
| Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $12, $1, and $(1), respectively | 22 |
| | 3 |
| | (2 | ) | |
| Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes (benefit) of $1, $(3), and $5, respectively | (4 | ) | | 4 |
| | (8 | ) | |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $22, $(32), and $6, respectively | 32 |
| | (46 | ) | | 4 |
| |
| Total other comprehensive income (loss), net of taxes | 50 |
| | (39 | ) | | (6 | ) | |
| Comprehensive Income (Loss) | $ | (924 | ) | | $ | 480 |
| | $ | 133 |
| |
| Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $16, $(6), and $(14), respectively | | 30 |
| | (8 | ) | | (19 | ) |
| Comprehensive Income from Continuing Operations Attributable to Ameren Corporation | | 542 |
| | 508 |
| | 412 |
|
| Net Income (Loss) Attributable to Ameren Corporation – Discontinued Operations | | (223 | ) | | (1,490 | ) | | 88 |
|
| Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes | | (19 | ) | | 50 |
| | (14 | ) |
| Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation | | (242 | ) | | (1,440 | ) | | 74 |
|
| Comprehensive Income (Loss) Attributable to Ameren Corporation | | $ | 300 |
| | $ | (932 | ) | | $ | 486 |
|
|
| | | | | | | |
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions) | December 31, 2012 | | December 31, 2011 |
| Assets: | | | |
| Cash and cash equivalents | $ | 23 |
| | $ | 3 |
|
| Advances to money pool | 316 |
| | 340 |
|
| Accounts and notes receivable - affiliates | 31 |
| | 57 |
|
| Other current assets | 49 |
| | — |
|
| Total current assets | 419 |
| | 400 |
|
| Investments in subsidiaries | 5,962 |
| | 7,482 |
|
| Note receivable - affiliates | 462 |
| | 425 |
|
| Other non-current assets | 320 |
| | 333 |
|
| Total assets | $ | 7,163 |
| | $ | 8,640 |
|
| Liabilities and Stockholders’ Equity: | | | |
| Short-term debt | $ | — |
| | $ | 148 |
|
| Accounts payable - affiliates | 10 |
| | 13 |
|
| Other current liabilities | 33 |
| | 62 |
|
| Total current liabilities | 43 |
| | 223 |
|
| Long-term debt | 424 |
| | 424 |
|
| Other deferred credits and liabilities | 80 |
| | 74 |
|
| Total liabilities | 547 |
| | 721 |
|
| Commitments and Contingencies | | | |
| Stockholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6 | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,616 |
| | 5,598 |
|
| Retained earnings | 1,006 |
| | 2,369 |
|
Accumulated other comprehensive income (loss)
| (8 | ) | | (50 | ) |
| Total stockholders’ equity | 6,616 |
| | 7,919 |
|
| Total liabilities and stockholders’ equity | $ | 7,163 |
| | $ | 8,640 |
|
|
| | | | | | | | | | | |
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010 |
| (In millions) | 2012 | | 2011 | | 2010 |
| Net cash flows provided by operating activities | $ | 532 |
| | $ | 804 |
| | $ | 241 |
|
| Cash flows from investing activities: | | | | | |
| Money pool advances, net | 24 |
| | (276 | ) | | 18 |
|
| Notes receivable - affiliates, net | (20 | ) | | 358 |
| | 242 |
|
| Investments in subsidiaries | (2 | ) | | (94 | ) | | (13 | ) |
| Distributions from subsidiaries | 21 |
| | 3 |
| | 1 |
|
| Other | (5 | ) | | (5 | ) | | — |
|
| Net cash flows provided by (used in) investing activities | 18 |
| | (14 | ) | | 248 |
|
| Cash flows from financing activities: | | | | | |
| Dividends on common stock | (382 | ) | | (375 | ) | | (368 | ) |
| Short-term debt and credit facility borrowings, net | (148 | ) | | (481 | ) | | (221 | ) |
| Issuances of common stock | — |
| | 65 |
| | 80 |
|
| Net cash flows used in financing activities | (530 | ) | | (791 | ) | | (509 | ) |
| Net change in cash and cash equivalents | $ | 20 |
| | $ | (1 | ) | | $ | (20 | ) |
| Cash and cash equivalents at beginning of year | 3 |
| | 4 |
| | 24 |
|
| Cash and cash equivalents at the end of year | $ | 23 |
| | $ | 3 |
| | $ | 4 |
|
| Cash dividends received from consolidated subsidiaries | $ | 610 |
| | $ | 730 |
| | $ | 368 |
|
| | | | | | |
| Noncash financing activity – dividends on common stock | $ | (7 | ) | | $ | — |
| | $ | — |
|
|
| | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET |
| (In millions) | December 31, 2013 | | December 31, 2012 |
| Assets: | | | |
| Cash and cash equivalents | $ | 11 |
| | $ | 23 |
|
| Advances to money pool | 334 |
| | 316 |
|
| Accounts and notes receivable – affiliates | 27 |
| | 31 |
|
| Miscellaneous accounts and notes receivable | 125 |
| | — |
|
| Other current assets | 42 |
| | 49 |
|
| Total current assets | 539 |
| | 419 |
|
| Investments in subsidiaries – continuing operations | 6,336 |
| | 6,315 |
|
| Investments in subsidiaries – discontinued operations | (5 | ) | | (353 | ) |
| Note receivable - affiliates | 51 |
| | 462 |
|
| Accumulated deferred income taxes, net | 623 |
| | 210 |
|
| Other non-current assets | 141 |
| | 110 |
|
| Total assets | $ | 7,685 |
| | $ | 7,163 |
|
| Liabilities and Stockholders’ Equity: | | | |
| Current maturities of long-term debt | $ | 425 |
| | $ | — |
|
| Short-term debt | 368 |
| | — |
|
| Accounts payable | 119 |
| | 3 |
|
| Accounts payable – affiliates | 4 |
| | 10 |
|
| Other current liabilities | 20 |
| | 30 |
|
| Total current liabilities | 936 |
| | 43 |
|
| Long-term debt | — |
| | 424 |
|
| Other deferred credits and liabilities | 205 |
| | 80 |
|
| Total liabilities | 1,141 |
| | 547 |
|
| Commitments and Contingencies | | | |
| Stockholders’ Equity: | | | |
| Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6 | 2 |
| | 2 |
|
| Other paid-in capital, principally premium on common stock | 5,632 |
| | 5,616 |
|
| Retained earnings | 907 |
| | 1,006 |
|
| Accumulated other comprehensive income (loss) | 3 |
| | (8 | ) |
| Total stockholders’ equity | 6,544 |
| | 6,616 |
|
| Total liabilities and stockholders’ equity | $ | 7,685 |
| | $ | 7,163 |
|
|
| | | | | | | | | | | |
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011 |
| (In millions) | 2013 | | 2012 | | 2011 |
| Net cash flows provided by operating activities | $ | 453 |
| | $ | 532 |
| | $ | 804 |
|
| Cash flows from investing activities: | | | | | |
| Money pool advances, net | (371 | ) | | 24 |
| | (276 | ) |
| Notes receivable – affiliates, net | (23 | ) | | (20 | ) | | 358 |
|
| Investments in subsidiaries | (50 | ) | | (2 | ) | | (94 | ) |
| Distributions from subsidiaries | 1 |
| | 21 |
| | 3 |
|
| Other | (2 | ) | | (5 | ) | | (5 | ) |
| Net cash flows provided by (used in) investing activities | (445 | ) | | 18 |
| | (14 | ) |
| Cash flows from financing activities: | | | | | |
| Dividends on common stock | (388 | ) | | (382 | ) | | (375 | ) |
| Short-term debt and credit facility borrowings, net | 368 |
| | (148 | ) | | (481 | ) |
| Issuances of common stock | — |
| | — |
| | 65 |
|
| Net cash flows used in financing activities | (20 | ) | | (530 | ) | | (791 | ) |
| Net change in cash and cash equivalents | $ | (12 | ) | | $ | 20 |
| | $ | (1 | ) |
| Cash and cash equivalents at beginning of year | 23 |
| | 3 |
| | 4 |
|
| Cash and cash equivalents at the end of year | $ | 11 |
| | $ | 23 |
| | $ | 3 |
|
| Cash dividends received from consolidated subsidiaries | $ | 570 |
| | $ | 610 |
| | $ | 730 |
|
| | | | | | |
| Noncash investing activity – divestiture | $ | 494 |
| | $ | — |
| | $ | — |
|
| Noncash financing activity – dividends on common stock | — |
| | (7 | ) | | — |
|
AMEREN CORPORATION (parent company only)
NOTES TO CONDENSED FINANCIAL STATEMENTS
December 31, 20122013
NOTE 1 -– BASIS OF PRESENTATION
Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. As specified in Note 5 - Long-term Debt and Equity Financings under Part II, Item 8, of this report, there are restrictions on Ameren Corporation’s (parent company only) ability to obtain funds from certain of its subsidiaries through dividends, loans or advances. In accordance with authoritative accounting guidance, 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 within the combined notes under Part II, Item 8, of this report.
NOTE 2 -– SHORT-TERM DEBT AND LIQUIDITY
See Note 4 -– Short-term Debt and Liquidity under Part II, Item 8, of this report for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).
NOTE 3 -– 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 4 -– COMMITMENTS AND CONTINGENCIES
See Note 14 - Related Party15 – Commitments and Contingencies and Note 16 – Divestiture Transactions and Note 15 - Commitments and ContingenciesDiscontinued Operations 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 5 - IMPAIRMENTS
– NEW AER DIVESTITURE AND DISCONTINUED OPERATIONS
In December 2012, Ameren determined that it intendsintended to, and it iswas probable that it will,would, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren's analysis of the current and projected future financial condition of its Merchant Generation segment and its conclusion that this segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately
eliminate, the Merchant Generation segment's reliance on Ameren's financial support and shared services support. Ameren's date and method of exit from the Merchant Generation business is currently uncertain.
As a result of the announcement that Ameren intends to exit the Merchant Generation segment before the end of the Merchant Generation's long-lived assets' previously estimated useful lives, Ameren determined that estimated undiscounted cash flows during the period in which it expects to continue to own certain energy centers would be insufficient to recover the carrying value of those energy centers. Accordingly, in the fourth quarter of 2012 determination, Ameren Corporation (parent company only) recorded a noncash pretax impairment charge of $1.88$1.88 billion to reduce its investment in certain of the Merchant Generation segment's coal and natural gas-fired energy centers to their estimated fair values. This charge wasOn December 2, 2013, Ameren completed a divestiture that included a significant portion of that business. As a result of the divestiture in 2013, Ameren Corporation (parent company only) recorded a pretax loss on disposal of $201 million. These charges were included within "Equity in earnings (loss) of subsidiaries""Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations" in the Ameren Corporation (parent company only) Condensed Statement of Income (Loss) and Comprehensive Income (Loss) for the yearyears ended December 31, 2013, and 2012.
During 2010, Ameren's Merchant Generation reporting unit failed step one of the interim goodwill impairment test, as the reporting unit's carrying value exceeded its estimated fair value. BasedThe "Miscellaneous accounts and notes receivable" on the results of step two of the goodwill impairment test,December 31, 2013 Ameren Corporation (parent company only) recordedCondensed Balance Sheet included a noncash impairment charge of $345 million, which represented allreceivable from Dynegy related to the non-state-regulated subsidiary money pool borrowing balance as of the goodwill assigneddivestiture date of certain New AER subsidiaries. Additionally, a payable to Ameren's Merchant Generation reporting unit recorded atDynegy of the estimated working capital adjustment required under the terms of the agreement with IPH is reflected in "Accounts payable" on the December 31, 2013 Ameren Corporation (parent company only).
Prior to 2010, Ameren's Merchant Generation expected to use its SO2 emission allowances for ongoing operations. In July 2010, Condensed Balance Sheet. Assuming IPH and Ameren reach an agreement, both the EPA issuedreceivable and the proposed CSAPR, which would have restrictedpayable will be finalized within 120 days after the useclosing of existing SO2 emission allowances. As a result, Merchant Generation no longer expected all of its SO2 emission allowances would be used in operations. Therefore, during 2010, Ameren Corporation (parent company only) recorded a $27 million pretax impairment charge to reduce the carrying value of SO2 emission allowances associated with Merchant Generation recorded at Ameren Corporation (parent company only), to their estimated fair value.divestiture.
See Note 17 - Impairment16 – Divestiture Transactions and Other ChargesDiscontinued Operations under Part II, Item 8, of this report for additional information on the impairment charges recognized in 2013 and 2012 and 2010.as well as the divestiture.
|
| | | | | | | | | | | | | | | | | | | |
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011 |
| (in millions) | | | | | | | | | |
| Column A | Column B | | Column C | | Column D | | Column E |
| Description | Balance at Beginning of Period | | (1) Charged to Costs and Expenses | | (2) Charged to Other Accounts(a) | | Deductions(b) | | Balance at End of Period |
| Ameren: | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | |
| 2013 | $ | 17 |
| | $ | 35 |
| | $ | 4 |
| | $ | 38 |
| | $ | 18 |
|
| 2012 | 20 |
| | 30 |
| | 2 |
| | 35 |
| | 17 |
|
| 2011 | 23 |
| | 41 |
| | — |
| | 44 |
| | 20 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2013 | $ | 2 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
| 2012 | 1 |
| | 1 |
| | — |
| | — |
| | 2 |
|
| 2011 | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Ameren Missouri: | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | |
| 2013 | $ | 5 |
| | $ | 16 |
| | $ | — |
| | $ | 16 |
| | $ | 5 |
|
| 2012 | 7 |
| | 11 |
| | — |
| | 13 |
| | 5 |
|
| 2011 | 8 |
| | 17 |
| | — |
| | 18 |
| | 7 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2013 | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| 2012 | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| 2011 | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Ameren Illinois: | | | | | | | | | |
| Deducted from assets – allowance for doubtful accounts: | | | | | | | | | |
| 2013 | $ | 12 |
| | $ | 19 |
| | $ | 4 |
| | $ | 22 |
| | $ | 13 |
|
| 2012 | 13 |
| | 19 |
| | 2 |
| | 22 |
| | 12 |
|
| 2011 | 13 |
| | 24 |
| | — |
| | 24 |
| | 13 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2013 | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| 2012 | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| 2011 | — |
| | — |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010 |
| (in millions) | | | | | | | | | |
| Column A | Column B | | Column C | | Column D | | Column E |
| Description | Balance at Beginning of Period | | (1) Charged to Costs and Expenses | | (2) Charged to Other Accounts(a) | | Deductions(b) | | Balance at End of Period |
| Ameren: | | | | | | | | | |
| Deducted from assets - allowance for doubtful accounts: | | | | | | | | | |
| 2012 | $ | 20 |
| | $ | 30 |
| | $ | 2 |
| | $ | 35 |
| | $ | 17 |
|
| 2011 | 23 |
| | 41 |
| | — |
| | 44 |
| | 20 |
|
| 2010 | 24 |
| | 33 |
| | — |
| | 34 |
| | 23 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2012 | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 4 |
|
| 2011 | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
| 2010 | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
| Ameren Missouri: | | | | | | | | | |
| Deducted from assets - allowance for doubtful accounts: | | | | | | | | | |
| 2012 | $ | 7 |
| | $ | 11 |
| | $ | — |
| | $ | 13 |
| | $ | 5 |
|
| 2011 | 8 |
| | 17 |
| | — |
| | 18 |
| | 7 |
|
| 2010 | 6 |
| | 14 |
| | — |
| | 12 |
| | 8 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2012 | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| 2011 | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| 2010 | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Ameren Illinois: | | | | | | | | | |
| Deducted from assets - allowance for doubtful accounts: | | | | | | | | | |
| 2012 | $ | 13 |
| | $ | 19 |
| | $ | 2 |
| | $ | 22 |
| | $ | 12 |
|
| 2011 | 13 |
| | 24 |
| | — |
| | 24 |
| | 13 |
|
| 2010 | 17 |
| | 18 |
| | — |
| | 22 |
| | 13 |
|
| Deferred tax valuation allowance: | | | | | | | | | |
| 2012 | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| 2011 | — |
| | — |
| | — |
| | — |
| | — |
|
| 2010 | — |
| | — |
| | — |
| | — |
| | — |
|
| |
| (a) | Uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers, as required by the Illinois Public UtilityUtilities Act. |
| |
| (b) | Uncollectible accounts charged off, less recoveries. |
SIGNATURES
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.
|
| | | | |
| | | AMEREN CORPORATION (registrant) |
| | | | |
| Date: | March 1, 20133, 2014 | By | | /s/ Thomas R. Voss |
| | | | | Thomas R. Voss Chairman President and Chief Executive Officer |
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.
|
| | | | | |
| /s/ Thomas R. Voss | | Chairman President and Chief Executive Officer, and Director (Principal Executive Officer) | | March 1, 20133, 2014 |
| Thomas R. Voss | | | |
|
| | | | |
| /s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | March 1, 20133, 2014 |
| Martin J. Lyons, Jr. | | | | |
| | | | | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer) | | March 1, 20133, 2014 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | March 1, 20133, 2014 |
Stephen F. Brauer Warner L. Baxter | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Catherine S. Brune | |
| | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Ellen M. Fitzsimmons | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Walter J. Galvin | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Richard J. Harshman | | | | |
| | | |
| * | | Director | | March 3, 2014 |
| Gayle P.W. Jackson | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| James C. Johnson | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Steven H. Lipstein | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Patrick T. Stokes | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Stephen R. Wilson | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Jack D. Woodard | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | March 1, 20133, 2014 |
| | Martin J. Lyons, Jr. | | | | |
| | Attorney-in-Fact | | | | |
|
| | | | |
| | | UNION ELECTRIC COMPANY (registrant) |
| | | | |
| Date: | March 1, 20133, 2014 | By | | /s/ Warner L. Baxter |
| | | | | Warner L. Baxter Chairman, President and Chief Executive Officer |
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.
|
| | | | | |
| /s/ Warner L. Baxter | | Chairman, President and Chief Executive Officer, and Director (Principal Executive Officer) | | March 1, 20133, 2014 |
| Warner L. Baxter | |
| | |
| | | | |
/s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | March 1, 20133, 2014 |
| Martin J. Lyons, Jr. | | | | |
| | | | |
/s/ Bruce A. Steinke | | Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer) | | March 1, 20133, 2014 |
| Bruce A. Steinke | | | | |
| | | | | | |
| * | | Director | | March 1, 20133, 2014 |
| Daniel F. Cole | | | | |
| | | | |
| * | | Director | | March 1, 2013 |
Adam C. Heflin | | | | |
| | | |
* | | Director | | March 1, 20133, 2014 |
| Michael L. Moehn | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Charles D. Naslund | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Gregory L. Nelson | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | March 1, 20133, 2014 |
| | Martin J. Lyons, Jr. | | | | |
| | Attorney-in-Fact | | | | |
|
| | | | |
| | | AMEREN ILLINOIS COMPANY (registrant) |
| | | | | |
| Date: | March 1, 20133, 2014 | By | | /s/ Richard J. Mark |
| | | | | Richard J. Mark Chairman, President and Chief Executive Officer |
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.
|
| | | | | |
| /s/ Richard J. Mark | | Chairman, President and Chief Executive Officer, Chief Executive Officer, and Director (Principal Executive Officer) | | March 1, 20133, 2014 |
| Richard J. Mark | |
| | |
| | | | |
| /s/ Martin J. Lyons, Jr. | | Executive Vice President and Chief Financial Officer, and Director (Principal Financial Officer) | | March 1, 20133, 2014 |
| Martin J. Lyons, Jr. | |
| | |
| | | | |
| /s/ Bruce A. Steinke | | Senior Vice President, Finance and Chief Accounting Officer (Principal Accounting Officer) | | March 1, 20133, 2014 |
| Bruce A. Steinke | |
| | |
| | | | | | |
| * | | Director | | March 1, 20133, 2014 |
| Daniel F. Cole | | | | |
| | | | |
| * | | Director | | March 1, 20133, 2014 |
| Gregory L. Nelson | | | | |
| | | | |
| *By | /s/ Martin J. Lyons, Jr. | | | | March 1, 20133, 2014 |
| | Martin J. Lyons, Jr. | | | | |
| | Attorney-in-Fact | | | | |
EXHIBIT INDEX
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: |
| | | |
| Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: |
| Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession |
| 2.1 | Ameren Illinois | Agreement and Plan of Merger, dated as of April 13, 2010, among CIPS, CILCO and IP | Annex A to Part I of the Registration Statement on Form S-4, File No. 333-166095). |
| 2.2 | Ameren | Transaction Agreement, dated as of March 14, 2013, between Ameren Corporation and Illinois Power Holdings, LLC | March 19, 2013 Form 8-K, Exhibit 2.1, File No. 1-14756 |
| 2.3 | Ameren | Letter Agreement, dated December 2, 2013, between Ameren Corporation and Illinois Power Holdings, LLC, amending the Transaction Agreement, dated as of March 14, 2013 | December 4, 2013 Form 8-K, Exhibit 2.2, File No. 1-14756 |
| Articles of Incorporation/ By-Laws |
| 3.1(i) | Ameren | Restated Articles of Incorporation of Ameren | Annex F to Part I of the Registration Statement on Form S-4, File No. 33-64165 |
| 3.2(i) | Ameren | Certificate of Amendment to Ameren's Restated Articles of Incorporation filed December 14, 1998 | 1998 Form 10-K, Exhibit 3(i), File No. 1-14756 |
| 3.3(i) | Ameren | Certificate of Amendment to Ameren's Restated Articles of Incorporation filed April 21, 2011 | April 21, 2011 Form 8-K, Exhibit 3(i), File No. 1-14756 |
| 3.4(i) | Ameren | Certificate of Amendment to Ameren's Restated Articles of Incorporation filed December 18, 2012 | December 18, 2012 Form 8-K, Exhibit 3.1(i), File No. 1-14756 |
| 3.5(i) | Ameren Missouri | Restated Articles of Incorporation of Ameren Missouri | 1993 Form 10-K, Exhibit 3(i), File No. 1-2967 |
| 3.6(i) | Ameren Illinois | Restated Articles of Incorporation of Ameren Illinois | 2010 Form 10-K, Exhibit 3.4(i), File No. 1-3672 |
| 3.7(ii) | Ameren | By-Laws of Ameren, as amended December 14, 2012 | December 18, 2012 Form 8-K, Exhibit 3.1(ii), File No. 1-14756 |
| 3.8(ii) | Ameren Missouri | By-Laws of Ameren Missouri, as amended December 10, 2010 | December 15, 2010 Form 8-K, Exhibit 3.1(ii), File No. 1-2967 |
| 3.9(ii) | Ameren Illinois | Bylaws of Ameren Illinois, as amended December 10, 2010 | December 15, 2010 Form 8-K, Exhibit 3.2(ii), File No. 1-3672 |
| Instruments Defining Rights of Security Holders, Including Indentures |
| 4.1 | Ameren | Indenture dated as of December 1, 2001 from Ameren to The Bank of New York Mellon Trust Company, N.A., as successor trustee, relating to senior debt securities (Ameren Indenture) | Exhibit 4.5, File No. 333-81774 |
| 4.2 | Ameren | First Supplemental Indenture to Ameren Senior Indenture dated as of May 19, 2008 | June 30, 2008 Form 10-Q, Exhibit 4.1, File No. 1-14756 |
| 4.3 | Ameren | Ameren Indenture Company Order dated May 15, 2009, establishing 8.875% Senior Notes, due 2014 (including the global note) | May 15, 2009 Form 8-K, Exhibits 4.3 and 4.4, File No. 1-14756 |
| 4.4 | Ameren Ameren Missouri | Indenture of Mortgage and Deed of Trust dated June 15, 1937 (Ameren Missouri Mortgage), from Ameren Missouri to The Bank of New York Mellon, as successor trustee, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941 | Exhibit B-1, File No. 2-4940 |
| 4.5 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated as of July 1, 1956 | August 2, 1956 Form 8-K, Exhibit 2, File No. 1-2967 |
| 4.6 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated as of April 1, 1971 | April 1971 Form 8-K, Exhibit 6, File No. 1-2967 |
| 4.7 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated as of February 1, 1974 | February 1974 Form 8-K, Exhibit 3, File No. 1-2967 |
| 4.8 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated as of July 7, 1980 | Exhibit 4.6, File No. 2-69821 |
| 4.9 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated as of October 1, 1993, relative to Series 2028 | 1993 Form 10-K, Exhibit 4.8, File No. 1-2967 |
| 4.10 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated as of February 1, 2000 | 2000 Form 10-K, Exhibit 4.1, File No. 1-2967 |
|
| | | |
| 4.11 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated August 15, 2002 | August 23, 2002 Form 8-K, Exhibit 4.3, File No. 1-2967 |
| 4.12 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated March 5, 2003, relative to Series BB | March 11, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.13 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated April 1, 2003, relative to Series CC | April 10, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 |
|
| | | |
| 4.14 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated July 15, 2003, relative to Series DD | August 4, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.15 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated October 1, 2003, relative to Series EE | October 8, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.16 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004A (1998A) | March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967 |
| 4.17 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004B (1998B) | March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967 |
| 4.18 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004C (1998C) | March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967 |
| 4.19 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated February 1, 2004, relative to Series 2004H (1992) | March 31, 2004 Form 10-Q, Exhibit 4.8, File No. 1-2967 |
| 4.20 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated May 1, 2004 relative to Series FF | May 18, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.21 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated September 1, 2004 relative to Series GG | September 23, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.22 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated January 1, 2005 relative to Series HH | January 27, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.23 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated July 1, 2005 relative to Series II | July 21, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.24 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated December 1, 2005 relative to Series JJ | December 9, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.25 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated June 1, 2007 relative to Series KK | June 15, 2007 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.26 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated April 1, 2008 relative to Series LL | April 8, 2008 Form 8-K, Exhibit 4.7, File No. 1-2967 |
| 4.27 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated June 1, 2008 relative to Series MM | June 19, 2008 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.28 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated March 1, 2009 relative to Series NN | March 23, 2009 Form 8-K, Exhibit 4.5, File No. 1-2967 |
| 4.29 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated May 15, 2012 | Exhibit 4.45, File No. 333-182258 |
| 4.30 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated September 1, 2012 relative to Series OO | September 11, 2012 Form 8-K, Exhibit 4.4, File No. 1-2967 |
| 4.31 | Ameren Ameren Missouri | Loan Agreement dated as of December 1, 1992, between the Missouri Environmental Authority and Ameren Missouri, together with Indenture of Trust dated as of December 1, 1992, between the Missouri Environmental Authority and UMB Bank, N.A. as successor trustee to Mercantile Bank of St. Louis, N.A. | 1992 Form 10-K, Exhibit 4.38, File No. 1-2967 |
| 4.32 | Ameren Ameren Missouri | First Amendment dated as of February 1, 2004, to Loan Agreement dated as of December 1, 1992, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.10, File No. 1-2967 |
| 4.33 | Ameren Ameren Missouri | Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | September 30, 1998 Form 10-Q, Exhibit 4.28, File No. 1-2967 |
| 4.34 | Ameren Ameren Missouri | First Amendment dated as of February 1, 2004, to Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.11, File No. 1-2967 |
| 4.35 | Ameren Ameren Missouri | Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | September 30, 1998 Form 10-Q, Exhibit 4.29, File No. 1-2967 |
|
| | | |
| 4.36 | Ameren Ameren Missouri | First Amendment dated as of February 1, 2004, to Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.12, File No. 1-2967 |
| 4.37 | Ameren Ameren Missouri | Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | September 30, 1998 Form 10-Q, Exhibit 4.30, File No. 1-2967 |
|
| | | |
| 4.38 | Ameren Ameren Missouri | First Amendment dated as of February 1, 2004, to Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and Ameren Missouri | March 31, 2004 Form 10-Q, Exhibit 4.13, File No. 1-2967 |
| 4.39 | Ameren Ameren Missouri | Indenture dated as of August 15, 2002, from Ameren Missouri to The Bank of New York Mellon, as successor trustee (relating to senior secured debt securities) (Ameren Missouri Indenture) | August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967 |
| 4.40 | Ameren Ameren Missouri | First Supplemental Indenture to the Ameren Missouri Indenture, dated as of May 15, 2012 | Exhibit 4.48, File No. 333-182258 |
| 4.41 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated March 10, 2003, establishing the 5.50% Senior Secured Notes due 2034 (including the global note) | March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.42 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated April 9, 2003, establishing the 4.75% Senior Secured Notes due 2015 (including the global note) | April 10, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.43 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated July 28, 2003, establishing the 5.10% Senior Secured Notes due 2018 (including the global note) | August 4, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.44 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated October 7, 2003, establishing the 4.65% Senior Secured Notes due 2013 (including the global note) | October 8, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.45 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated May 13, 2004, establishing the 5.50% Senior Secured Notes due 2014 (including the global note) | May 18, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.46 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated September 1, 2004, establishing the 5.10% Senior Secured Notes due 2019 (including the global note) | September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.47 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated January 27, 2005, establishing the 5.00% Senior Secured Notes due 2020 (including the global note) | January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.48 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated July 21, 2005, establishing the 5.30% Senior Secured Notes due 2037 (including the global note) | July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.49 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated December 8, 2005, establishing the 5.40% Senior Secured Notes due 2016 (including the global note) | December 9, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.50 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated June 15, 2007, establishing the 6.40% Senior Secured Notes due 2017 (including the global note) | June 15, 2007 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.51 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated April 8, 2008, establishing the 6.00% Senior Secured Notes due 2018 (including the global note) | April 8, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967 |
| 4.52 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated June 19, 2008, establishing the 6.70% Senior Secured Notes due 2019 (including the global note) | June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.53 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated March 20, 2009, establishing 8.45% Senior Secured Notes due 2039 (including the global note) | March 23, 2009 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967 |
| 4.54 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated September 11, 2012, establishing 3.90% Senior Secured Notes due 2042 (including the global note) | September 30, 2012 Form 10-Q, Exhibit 4.1 and September 11, 2012 Form 8-K, Exhibit 4.2, File No. 1-2967 |
| 4.55 | Ameren Ameren Illinois | Indenture dated as of December 1, 1998, from Central Illinois Public Service Company (now known as Ameren Illinois) to The Bank of New York Mellon Trust Company, N.A., as successor trustee (CIPS Indenture) | Exhibit 4.4, File No. 333-59438 |
| 4.56 | Ameren Ameren Illinois | First Supplemental Indenture to the CIPS Indenture, dated as of June 14, 2006 | June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672 |
| 4.57 | Ameren Ameren Illinois | Second Supplemental Indenture to the CIPS Indenture, dated as of March 1, 2010 | Exhibit 4.17, File No. 333-166095 |
| 4.58 | Ameren Ameren Illinois | Third Supplemental Indenture to the CIPS Indenture, dated as of October 1, 2010 | 2010 Form 10-K, Exhibit 4.59, File No. 1-3672 |
| 4.59 | Ameren Ameren Illinois | Ameren Illinois Global Note, dated October 1, 2010, representing CIPS Indenture Senior Notes, 6.125% due 2028 | 2010 Form 10-K, Exhibit 4.60, File No. 1-3672 |
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| 4.60 | Ameren Ameren Illinois | Ameren Illinois Global Note, dated October 1, 2010, representing CIPS Indenture Senior Notes, 6.70% Series Secured Notes due 2036 | 2010 Form 10-K, Exhibit 4.62, File No. 1-3672 |
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| 4.61 | Ameren Ameren Illinois | Indenture of Mortgage and Deed of Trust between Illinois Power Company (predecessor in interest to CILCO and Ameren Illinois) and Bankers Trust Company (now known as Deutsche Bank Trust Company Americas), as trustee, dated as of April 1, 1933 (CILCO Mortgage), Supplemental Indenture between the same parties dated as of June 30, 1933, Supplemental Indenture between CILCO (predecessor in interest to Ameren Illinois) and the trustee, dated as of July 1, 1933, Supplemental Indenture between the same parties dated as of January 1, 1935, and Supplemental Indenture between the same parties dated as of April 1, 1940 | Exhibit B-1, Registration No. 2-1937; Exhibit B-1(a), Registration No. 2-2093; and Exhibit A, April 1940 Form 8-K, File No. 1-2732 |
| 4.62 | Ameren Ameren Illinois | Supplemental Indenture to the CILCO Mortgage, dated December 1, 1949 | December 1949 Form 8-K, Exhibit A, File No. 1-2732 |
| 4.63 | Ameren Ameren Illinois | Supplemental Indenture to the CILCO Mortgage, dated July 1, 1957 | July 1957 Form 8-K, Exhibit A, File No. 1-2732 |
| 4.64 | Ameren Ameren Illinois | Supplemental Indenture to the CILCO Mortgage, dated February 1, 1966 | February 1966 Form 8-K, Exhibit A, File No. 1-2732 |
| 4.65 | Ameren Ameren Illinois | Supplemental Indenture to the CILCO Mortgage, dated January 15, 1992 | January 30, 1992 Form 8-K, Exhibit 4(b), File No. 1-2732 |
| 4.66 | Ameren Ameren Illinois | Supplemental Indenture to the CILCO Mortgage, dated June 1, 2006 for the Series AA and BB | June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732 |
| 4.67 | Ameren Ameren Illinois | Supplemental Indenture to the CILCO Mortgage, dated December 1, 2008 for the Series CC | December 9, 2008 Form 8-K, Exhibit 4.5, File No. 1-2732 |
| 4.68 | Ameren Ameren Illinois | Supplemental Indenture to the CILCO Mortgage, dated as of October 1, 2010 | October 7, 2010 Form 8 K, Exhibit 4.4, File No. 1-14756 |
| 4.69 | Ameren Ameren Illinois | Indenture dated as of June 1, 2006, from CILCO (predecessor in interest to Ameren Illinois) to The Bank of New York Mellon Trust Company, N.A., as successor trustee (CILCO Indenture) | June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-2732 |
| 4.70 | Ameren Ameren Illinois | First Supplemental Indenture to the CILCO Indenture, dated October 1, 2010 | October 7, 2010 Form 8 K, Exhibit 4.1, File No. 1-3672 |
| 4.71 | Ameren Ameren Illinois | Second Supplemental Indenture to the CILCO Indenture dated as of July 21, 2011 | September 30, 2011 Form 10-Q, Exhibit 4.1, File No. 1-3672 |
| 4.72 | Ameren Ameren Illinois | CILCO Indenture Company Order, dated June 14, 2006, establishing the 6.20% Senior Secured Notes due 2016 (including the global note) and the 6.70% Senior Secured Notes due 2036 (including the global note) | June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732 |
| 4.73 | Ameren Ameren Illinois | CILCO Indenture Company Order, dated December 9, 2008, establishing the 8.875% Senior Secured Notes due 2013 (including the global note) | December 9, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2732 |
| 4.74 | Ameren Ameren Illinois | General Mortgage Indenture and Deed of Trust dated as of November 1, 1992 between Illinois Power Company (predecessor in interest to Ameren Illinois) and The Bank of New York Mellon Trust Company, N.A., as successor trustee (Ameren Illinois Mortgage) | 1992 Form 10-K, Exhibit 4(cc), File No. 1-3004 |
| 4.75 | Ameren Ameren Illinois | Supplemental Indenture dated as of March 1, 1998, to Ameren Illinois Mortgage for Series S | Exhibit 4.41, File No. 333-71061 |
| 4.76 | Ameren Ameren Illinois | Supplemental Indenture dated as of March 1, 1998, to Ameren Illinois Mortgage for Series T | Exhibit 4.42, File No. 333-71061 |
| 4.77 | Ameren Ameren Illinois | Supplemental Indenture amending the Ameren Illinois Mortgage dated as of June 15, 1999 | June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004 |
| 4.78 | Ameren Ameren Illinois | Supplemental Indenture dated as of July 15, 1999, to Ameren Illinois Mortgage for Series U | June 30, 1999 Form 10-Q, Exhibit 4.4, File No. 1-3004 |
| 4.79 | Ameren Ameren Illinois | Supplemental Indenture amending the Ameren Illinois Mortgage dated as of December 15, 2002 | December 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-3004 |
| 4.80 | Ameren Ameren Illinois | Supplemental Indenture dated as of June 1, 2006, to Ameren Illinois Mortgage for Series AA | June 19, 2006 Form 8-K, Exhibit 4.13, File No. 1-3004 |
| 4.81 | Ameren Ameren Illinois | Supplemental Indenture dated as of November 15, 2007, to Ameren Illinois Mortgage for Series BB | November 20, 2007 Form 8-K, Exhibit 4.4, File No. 1-3004 |
| 4.82 | Ameren Ameren Illinois | Supplemental Indenture dated as of April 1, 2008, to Ameren Illinois Mortgage for Series CC | April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004 |
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| 4.83 | Ameren Ameren Illinois | Supplemental Indenture dated as of October 1, 2008, to Ameren Illinois Mortgage for Series DD | October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
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| 4.84 | Ameren Ameren Illinois | Supplemental Indenture, dated as of October 1, 2010, to Ameren Illinois Mortgage for Series CIPS-AA, CIPS-BB and CIPS-CC | October 7, 2010 Form 8 K, Exhibit 4.9, File No. 1-3672 |
| 4.85 | Ameren Ameren Illinois | Supplemental Indenture, dated as of January 15, 2011, to Ameren Illinois Mortgage | Exhibit 4.78, File No. 333-182258 |
| 4.86 | Ameren Ameren Illinois | Supplemental Indenture dated as of August 1, 2012, to Ameren Illinois Mortgage for Series EE | August 20, 2012 Form 8-K, Exhibit 4.4, File No. 1-3672 |
| 4.87 | Ameren Ameren Illinois | Supplemental Indenture, dated as of December 1, 2013, to Ameren Illinois Mortgage for Series FF | December 10, 2013 Form 8-K, Exhibit 4.5, File No. 1-3672 |
| 4.88 | Ameren Ameren Illinois | Indenture, dated as of June 1, 2006 from IP (predecessor in interest to Ameren Illinois) to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Ameren Illinois Indenture) | June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.884.89 | Ameren Ameren Illinois | First Supplemental Indenture, dated as of October 1, 2010, to the Ameren Illinois Indenture for Series CIPS-AA, CIPS-BB and CIPS-CC | October 7, 2010 Form 8 K, Exhibit 4.5, File No. 1-14756 |
4.894.90 | Ameren Ameren Illinois | Second Supplemental Indenture to the Ameren Illinois Indenture dated as of July 21, 2011 | September 30, 2011 Form 10-Q, Exhibit 4.2, File No. 1-3672 |
4.904.91 | Ameren Ameren Illinois | Third Supplemental Indenture to the Ameren Illinois Indenture dated as of May 15, 2012 | Exhibit 4.83, File No. 333-182258 |
4.914.92 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order, dated June 14, 2006, establishing the 6.25% Senior Secured Notes due 2016 (including the global note) | June 19, 2006 Form 8-K, Exhibit 4.7, File No. 1-3004 |
4.924.93 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order, dated November 15, 2007, establishing 6.125% Senior Secured Notes due 2017 (including the global note) | November 20, 2007 Form 8-K, Exhibit 4.2, File No. 1-3004 |
4.934.94 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order, dated April 8, 2008, establishing 6.25% Senior Secured Notes due 2018 (including the global note) | April 8, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004 |
4.944.95 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order dated October 23, 2008, establishing 9.75% Senior Secured Notes due 2018 (including the global note) | October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004 |
4.954.96 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order dated August 20, 2012, establishing 2.70% Senior Secured Notes due 2022 (including the global note) | August 20, 2012 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-3004 |
4.964.97 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order dated December 10, 2013, establishing 4.80% Senior Secured Notes due 2043 (including the global note) | Indenture dated as of November 1, 2000, from Genco to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Genco Indenture) | Exhibit 4.1, File No. 333-56594 |
4.97 | Ameren | Third Supplemental Indenture dated as of June 1, 2002, to Genco Indenture, relating to Genco's 7.95% Senior Notes, Series E due 2032 | June 30, 2002 Form 10-Q, Exhibit 4.1, File No. 1-14756 |
4.98 | Ameren | Fourth Supplemental Indenture dated as of January 15, 2003, to Genco Indenture, relating to Genco 7.95% Senior Notes, Series F due 2032 | 2002 Form 10-K, Exhibit 4.5, File No. 1-14756 |
4.99 | Ameren | Fifth Supplemental Indenture dated as of April 1, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series G due 2018 | April 9, 2008December 10, 2013 Form 8-K, Exhibit 4.2, File No. 1-14756 |
4.100 | Ameren | Sixth Supplemental Indenture, dated as of July 7, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series H due 2018 | Exhibit No. 4.55, File No. 333-155416 |
4.101 | Ameren | Seventh Supplemental Indenture, dated as of November 1, 2009, to Genco Indenture, relating to Genco 6.30% Senior Notes, Series l due 2020 | November 17, 2009 Form 8-K, Exhibit 4.8, File No. 1-147561-3672 |
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| 10.1 | Ameren Ameren Illinois | Unilateral Borrowing Agreement by and among Ameren, IP (predecessor in interest to Ameren Illinois) and Ameren Services, dated as of September 30, 2004 | October 1, 2004 Form 8-K, Exhibit 10.3, File No. 1-3004 |
| 10.2 | Ameren Companies | Third Amended Ameren Corporation System Utility Money Pool Agreement, as amended September 30, 2004 | October 1, 2004 Form 8-K, Exhibit 10.2, File No. 1-14756 |
| 10.3 | Ameren | Ameren Corporation System Amended and Restated Non-Regulated Subsidiary Money Pool Agreement, dated March 1, 2008 | March 31, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.4 | Ameren Ameren Missouri | Credit Agreement, dated as of November 14, 2012, by and among Ameren, Ameren Missouri and JPMorgan Chase Bank, N.A., as agent, and the lenders party thereto. | November 15, 2012 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.510.4 | Ameren Ameren Illinois | Credit Agreement, dated as of November 14, 2012, by and among Ameren, Ameren Illinois and JPMorgan Chase Bank, N.A., as agent, and the lenders party thereto. | November 15, 2012 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.6
| Ameren | Put Option Agreement, dated as of March 28, 2012, between Genco and AERG | March 28, 2012 Form 8-K, Exhibit 10.1, File No. 1-14756 |
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10.7 | Ameren | Guaranty, dated as of March 28, 2012, made by Ameren in favor of Genco | March 28, 2012 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.810.5 | Ameren | *Summary Sheet of Ameren Corporation Non-Management Director Compensation revised on August 8, 20089, 2013 and effective as of August 12, 2013 | September 30, 20082013 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.910.6 | Ameren | *Ameren's Deferred Compensation Plan for Members of the Board of Directors amended and restated effective January 1, 2009, dated June 13, 2008 | June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756 |
10.1010.7 | Ameren Companies | *Amendment dated October 12, 2009, to Ameren's Deferred Compensation Plan for Members of the Board of Directors, effective January 1, 2010 | 2009 Form 10-K, Exhibit 10.15 , File No. 1-14756 |
10.1110.8 | Ameren Companies | *Amendment dated October 14, 2010, to Ameren's Deferred Compensation Plan for Members of the Board of Directors | 2010 Form 10-K, Exhibit 10.15, File No. 1-14756 |
10.1210.9 | Ameren Companies | *Ameren's Deferred Compensation Plan as amended and restated effective January 1, 2010 | October 14, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.1310.10 | Ameren Companies | *Amendment dated October 14, 2010 to Ameren's Deferred Compensation Plan | 2010 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.14 |
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| 10.11 | Ameren Companies | *2012 Ameren Executive Incentive Plan | December 14, 2011 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.1510.12 | Ameren Companies | *2013 Ameren Executive Incentive Plan | December 18, 2012 Form 8-K, Exhibit 10.1, File No. 1-14756 |
10.1610.13 | Ameren Companies | *2012 Base Salary Table for Named Executive Officers | 2011 Form 10-K, Exhibit 10.23, File No. 1-14756 |
10.1710.14 | Ameren Companies | *2013 Base Salary Table for Named Executive Officers | 2012 Form 10-K, Exhibit 10.17, File No. 1-14756 |
10.1810.15 | Ameren Companies | *2014 Base Salary Table for Named Executive Officers | |
| 10.16 | Ameren Companies | *Second Amended and Restated Ameren Corporation Change of Control Severance Plan | 2008 Form 10-K, Exhibit 10.37, File No. 1-14756 |
10.1910.17 | Ameren Companies | *First Amendment dated October 12, 2009, to the Second Amended and Restated Ameren Change of Control Severance Plan | October 14, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.2010.18 | Ameren Companies | *Revised Schedule I to Second Amended and Restated Ameren Change of Control Severance Plan, as amended | September 30, 20122013 Form 10-Q, Exhibit 10.2, File No. 1-14756 |
10.21 | Ameren Companies | *Formula for Determining 2010 Target Performance Share Unit Awards to be Issued to Named Executive Officers | December 17, 2009 Form 8-K, Exhibit 99.1, File No. 1-14756 |
10.2210.19 | Ameren Companies | *Formula for Determining 2011 Target Performance Share Unit Awards to be Issued to Named Executive Officers | December 15, 2010 Form 8-K, Exhibit 99.1, File No. 1-14756 |
10.2310.20 | Ameren Companies | *Formula for Determining 2012 Target Performance Share Unit Awards to be Issued to Named Executive Officers | December 14, 2011 Form 8-K, Exhibit 99.1, File No. 1-14756 |
10.2410.21 | Ameren Companies | *Formula for Determining 2013 Target Performance Share Unit Awards to be Issued to Named Executive Officers | December 18, 2012 Form 8-K, Exhibit 99.1, File No. 1-14756 |
10.2510.22 | Ameren Companies | *Ameren Corporation 2006 Omnibus Incentive Compensation Plan | February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756 |
10.2610.23 | Ameren Companies | *Form of Performance Share Unit Award Agreement for Award Issued in 2010 pursuant to 2006 Omnibus Incentive Compensation Plan | December 17, 2009 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.27 | Ameren Companies | *Form of Performance Share Unit Award Agreement for AwardAwards Issued in 2011 pursuant to 2006 Omnibus Incentive Compensation Plan | December 15, 2010 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.2810.24 | Ameren Companies | *Form of Performance Share Unit Award Agreement for Awards Issued in 2012 pursuant to 2006 Omnibus Incentive Compensation Plan | December 14, 2011 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.2910.25 | Ameren Companies | *Form of Performance Share Unit Award Agreement for Awards Issued in 2013 pursuant to 2006 Omnibus Incentive Compensation Plan | December 18, 2012 Form 8-K, Exhibit 10.2, File No. 1-14756 |
10.3010.26 | Ameren Companies | *Performance Stock Bonus Award Agreement, dated March 1, 2011, between Ameren and Adam C. Heflin | March 31, 2011 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.3110.27 | Ameren Companies | *Ameren Supplemental Retirement Plan amended and restated effective January 1, 2008, dated June 13, 2008 | June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756 |
10.3210.28 | Ameren Companies | *First Amendment to amended and restated Ameren Supplemental Retirement Plan, dated October 24, 2008 | 2008 Form 10-K, Exhibit 10.44, File No. 1-14756 |
10.3310.29 | Ameren Ameren Illinois | *CILCO Executive Deferral Plan as amended effective August 15, 1999 | 1999 Form 10-K, Exhibit 10, File No. 1-2732 |
10.3410.30 | Ameren Ameren Illinois | *CILCO Executive Deferral Plan II as amended effective April 1, 1999 | 1999 Form 10-K, Exhibit 10(a), File No. 1-2732 |
10.3510.31 | Ameren Ameren Illinois | *CILCO Restructured Executive Deferral Plan (approved August 15, 1999) | 1999 Form 10-K, Exhibit 10(e), File No. 1-2732 |
10.3610.32 | Ameren Illinois | SeparationNovation and Amendment of Put Option Agreement, effective as of September 4, 2012, between Scott A. Ciseldated March 14, 2013, by and among Medina Valley, AERG, Genco and Ameren Illinois | September 30, 2012March 19, 2013 Form 10-Q,8-K, Exhibit 10.1,10.3, File No. 1-36721-14756 |
| 10.33 | Ameren | *Employment and Change of Control Agreement, dated March 13, 2013, between Steven R. Sullivan, AER and Ameren | March 19, 2013 Form 8-K, Exhibit 10.4, File No. 1-14756 |
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| Statement re: Computation of Ratios |
| 12.1 | Ameren | Ameren's Statement of Computation of Ratio of Earnings to Fixed Charges | |
| 12.2 | Ameren Missouri | Ameren Missouri's Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
| 12.3 | Ameren Illinois | Ameren Illinois' Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | |
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| Code of Ethics |
| 14.1 | Ameren Companies | Code of Ethics, as amended February 8, 2013 | 2012 Form 10-K, Exhibit 14.1, File No. 1-14756 |
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| Subsidiaries of the Registrant |
| 21.1 | Ameren Companies | Subsidiaries of Ameren | |
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| Consent of Experts and Counsel |
| 23.1 | Ameren | Consent of Independent Registered Public Accounting Firm with respect to Ameren | |
| 23.2 | Ameren Missouri | Consent of Independent Registered Public Accounting Firm with respect to Ameren Missouri | |
| 23.3 | Ameren Illinois | Consent of Independent Registered Public Accounting Firm with respect to Ameren Illinois | |
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| Power of Attorney |
| 24.1 | Ameren | PowerPowers of Attorney with respect to Ameren | |
| 24.2 | Ameren Missouri | Power of Attorney with respect to Ameren Missouri | |
| 24.3 | Ameren Illinois | Power of Attorney with respect to Ameren Illinois | |
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| Rule 13a-14(a)/15d-14(a) Certifications |
| 31.1 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren | |
| 31.2 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren | |
| 31.3 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri | |
| 31.4 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri | |
| 31.5 | Ameren Illinois | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois | |
| 31.6 | Ameren Illinois | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois | |
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| Section 1350 Certifications |
| 32.1 | Ameren | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren | |
| 32.2 | Ameren Missouri | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri | |
| 32.3 | Ameren Illinois | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois | |
| Additional Exhibits |
| 99.1 | Ameren Companies | Amended and Restated Tax Allocation Agreement, dated as of September 30, 2004November 21, 2013 | |
| Interactive Data File |
| 101.INS** | Ameren Companies | XBRL Instance Document | |
| 101.SCH** | Ameren Companies | XBRL Taxonomy Extension Schema Document | |
| 101.CAL** | Ameren Companies | XBRL Taxonomy Extension Calculation Linkbase Document | |
| 101.LAB** | Ameren Companies | XBRL Taxonomy Extension Label Linkbase Document | |
| 101.PRE** | Ameren Companies | XBRL Taxonomy Extension Presentation Linkbase Document | |
| 101.DEF** | Ameren Companies | XBRL Taxonomy Extension Definition Document | |
The file number references for the Ameren Companies' filings with the SEC are: Ameren, 1-14756; Ameren Missouri, 1-2967; and Ameren Illinois, 1-3672.
*Compensatory plan or arrangement.
**Attached as Exhibit 101 to this report is the following financial information for each of the Ameren Companies' Annual Report on Form 10-K for the year ended December 31, 2012,2013, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statement of Income (Loss) for the years ended December 31, 2013, 2012, 2011, and 2010,2011, (ii) the Consolidated Statement of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 2011 and 2010,2011, (iii) the Consolidated Balance Sheet at December 31, 20122013 and December 31, 2011,2012, (iv) the Consolidated Statement of Cash Flows for the years ended December 31, 2013, 2012, 2011, and 2010,2011, (v) the
Consolidated Statement of Stockholders' Equity for the years ended December 31, 2013, 2012, 2011, and 2010,2011, and (vi) the Combined Notes to the Financial Statements for the year ended December 31, 2012. For Ameren Missouri and Ameren Illinois, these exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.2013.
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.
