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Name | Symbol | Market | Type |
---|---|---|---|
Union Electric Company (PK) | USOTC:UELMO | OTCMarkets | Preference Share |
Price Change | % Change | Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 65.00 | 64.00 | 65.25 | 0.00 | 21:25:52 |
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Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended September 30, 2013
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¨
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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
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Exact name of registrant as specified in its charter;
State of Incorporation;
Address and Telephone Number
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IRS Employer
Identification No.
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1-14756
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Ameren Corporation
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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
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Union Electric Company
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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
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Ameren Illinois Company
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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) 343-8150
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Ameren Corporation
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Yes
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ý
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No
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¨
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Union Electric Company
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Yes
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ý
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No
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¨
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Ameren Illinois Company
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Yes
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ý
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No
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¨
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Ameren Corporation
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Yes
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ý
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No
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¨
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Union Electric Company
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Yes
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ý
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No
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¨
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Ameren Illinois Company
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Yes
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ý
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No
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¨
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Large Accelerated
Filer
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Accelerated
Filer
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Non-Accelerated
Filer
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Smaller Reporting
Company
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Ameren Corporation
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ý
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¨
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¨
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¨
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Union Electric Company
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¨
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¨
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ý
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¨
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Ameren Illinois Company
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¨
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¨
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ý
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¨
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Ameren Corporation
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Yes
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¨
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No
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ý
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Union Electric Company
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Yes
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¨
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No
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ý
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Ameren Illinois Company
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Yes
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¨
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No
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ý
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Ameren Corporation
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Common stock, $0.01 par value per share - 242,634,671
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Union Electric Company
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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
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Common stock, no par value, held by Ameren
Corporation (parent company of the registrant) - 25,452,373
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Page
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Item 1.
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Union Electric Company
(d/b/a Ameren Missouri)
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Ameren Illinois Company
(d/b/a Ameren Illinois)
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Item 2.
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Item 3.
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Item 4.
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Item 1.
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Item 1A.
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Item 2.
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Item 6.
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•
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completion of our divestiture of New AER, which is subject to Illinois Pollution Control Board approval of an Illinois MPS variance in favor of IPH on the same material terms as AER’s existing Illinois MPS variance, and completion of the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers, which is subject to FERC and other regulatory approvals;
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•
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Ameren's exit from the Merchant Generation business, which could result in additional impairments of long-lived assets, disposal-related losses, contingencies, reduction of existing deferred tax assets, or could have other adverse impacts on the financial condition, results of operations and liquidity of Ameren;
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•
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regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of Ameren Illinois' natural gas delivery service rate case filed in 2013; the court appeals of Ameren Illinois' electric rate order issued in 2012; Ameren Missouri's request with the MoPSC for an accounting authority order relating to the deferral of certain fixed costs; Ameren Illinois' request for rehearing of FERC’s July 2012 and June 2013 orders regarding the alleged inclusion of acquisition premiums in Ameren Illinois transmission rates; and future regulatory, judicial, or legislative actions that seek to change regulatory recovery mechanisms;
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•
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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;
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•
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the effects of Ameren Illinois’ expected participation, beginning in 2014, in the regulatory framework provided by the state of Illinois’ recently enacted Natural Gas Consumer, Safety and Reliability Act, which allows for the use of a rider
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•
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the effects of, or changes to, the Illinois power procurement process;
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•
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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;
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•
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changes in laws and other governmental actions, including monetary, fiscal, and tax policies, such as changes that result in our being unable to claim all or a portion of the cash tax benefits that are expected to result from the divestiture of AER;
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•
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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;
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•
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increasing capital expenditure and operating expense requirements and our ability to recover these costs;
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•
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the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;
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•
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the effectiveness of our risk management strategies and the use of financial and derivative instruments;
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•
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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;
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•
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business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products;
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•
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disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that make the Ameren Companies' access to necessary capital, including short-term credit and liquidity, impossible, more difficult, or more costly;
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•
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our assessment of our liquidity, including liquidity concerns for Ameren's Merchant Generation business, and specifically for Genco, whose ability to borrow additional funds from external, third-party sources is restricted;
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•
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the impact of the adoption of new accounting guidance and the application of appropriate technical accounting rules and guidance;
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•
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actions of credit rating agencies and the effects of such actions;
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•
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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;
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•
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the impact of system outages;
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•
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generation, transmission, and distribution asset construction, installation, performance, and cost recovery;
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•
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the effects of our increasing investment in electric transmission projects and uncertainty as to whether we will achieve our expected investment and returns in a timely fashion, if at all;
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•
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the extent to which Ameren Missouri prevails in its claims against insurers in connection with its Taum Sauk pumped-storage hydroelectric energy center incident;
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•
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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;
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•
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operation of Ameren Missouri's Callaway energy center, including planned, unplanned and refueling outages, and future decommissioning costs;
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•
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the effects of strategic initiatives, including mergers, acquisitions and divestitures, including the divestiture of the Merchant Generation business, and any related tax implications;
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•
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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;
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•
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the impact of complying with renewable energy portfolio requirements in Missouri;
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•
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labor disputes, workforce reductions, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets;
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•
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the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit agreements, and financial instruments;
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•
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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;
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•
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legal and administrative proceedings; and
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•
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acts of sabotage, war, terrorism, cybersecurity attacks or intentionally disruptive acts.
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Three Months Ended September 30,
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Nine Months Ended September 30,
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||||||||||||
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2013
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2012
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2013
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2012
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||||||||
Operating Revenues:
|
|
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||||||||
Electric
|
$
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1,507
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$
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1,579
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|
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$
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3,823
|
|
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$
|
3,898
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Gas
|
131
|
|
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130
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|
|
693
|
|
|
625
|
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||||
Total operating revenues
|
1,638
|
|
|
1,709
|
|
|
4,516
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|
|
4,523
|
|
||||
Operating Expenses:
|
|
|
|
|
|
|
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||||||||
Fuel
|
222
|
|
|
194
|
|
|
648
|
|
|
550
|
|
||||
Purchased power
|
128
|
|
|
260
|
|
|
400
|
|
|
630
|
|
||||
Gas purchased for resale
|
42
|
|
|
40
|
|
|
344
|
|
|
304
|
|
||||
Other operations and maintenance
|
383
|
|
|
362
|
|
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1,229
|
|
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1,126
|
|
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Depreciation and amortization
|
175
|
|
|
161
|
|
|
528
|
|
|
496
|
|
||||
Taxes other than income taxes
|
121
|
|
|
114
|
|
|
354
|
|
|
337
|
|
||||
Total operating expenses
|
1,071
|
|
|
1,131
|
|
|
3,503
|
|
|
3,443
|
|
||||
Operating Income
|
567
|
|
|
578
|
|
|
1,013
|
|
|
1,080
|
|
||||
Other Income and Expenses:
|
|
|
|
|
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||||||||
Miscellaneous income
|
20
|
|
|
17
|
|
|
51
|
|
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53
|
|
||||
Miscellaneous expense
|
5
|
|
|
6
|
|
|
18
|
|
|
28
|
|
||||
Total other income
|
15
|
|
|
11
|
|
|
33
|
|
|
25
|
|
||||
Interest Charges
|
88
|
|
|
99
|
|
|
289
|
|
|
295
|
|
||||
Income Before Income Taxes
|
494
|
|
|
490
|
|
|
757
|
|
|
810
|
|
||||
Income Taxes
|
187
|
|
|
179
|
|
|
288
|
|
|
298
|
|
||||
Income from Continuing Operations
|
307
|
|
|
311
|
|
|
469
|
|
|
512
|
|
||||
Income (Loss) from Discontinued Operations, Net of Taxes (Note 2)
|
(3
|
)
|
|
63
|
|
|
(212
|
)
|
|
(331
|
)
|
||||
Net Income
|
304
|
|
|
374
|
|
|
257
|
|
|
181
|
|
||||
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
|
|
|
|
|
|
|
|
||||||||
Continuing Operations
|
2
|
|
|
2
|
|
|
5
|
|
|
5
|
|
||||
Discontinued Operations
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(6
|
)
|
||||
Net Income (Loss) Attributable to Ameren Corporation:
|
|
|
|
|
|
|
|
||||||||
Continuing Operations
|
305
|
|
|
309
|
|
|
464
|
|
|
507
|
|
||||
Discontinued Operations
|
(3
|
)
|
|
65
|
|
|
(212
|
)
|
|
(325
|
)
|
||||
Net Income Attributable to Ameren Corporation
|
$
|
302
|
|
|
$
|
374
|
|
|
$
|
252
|
|
|
$
|
182
|
|
|
|
|
|
|
|
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|
||||||||
Earnings (Loss) per Common Share – Basic:
|
|
|
|
|
|
|
|
||||||||
Continuing Operations
|
$
|
1.26
|
|
|
$
|
1.28
|
|
|
$
|
1.92
|
|
|
$
|
2.09
|
|
Discontinued Operations
|
(0.01
|
)
|
|
0.26
|
|
|
(0.88
|
)
|
|
(1.34
|
)
|
||||
Earnings per Common Share – Basic
|
$
|
1.25
|
|
|
$
|
1.54
|
|
|
$
|
1.04
|
|
|
$
|
0.75
|
|
|
|
|
|
|
|
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|
||||||||
Earnings (Loss) per Common Share – Diluted:
|
|
|
|
|
|
|
|
||||||||
Continuing Operations
|
$
|
1.25
|
|
|
$
|
1.28
|
|
|
$
|
1.91
|
|
|
$
|
2.09
|
|
Discontinued Operations
|
(0.01
|
)
|
|
0.26
|
|
|
(0.88
|
)
|
|
(1.34
|
)
|
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Earnings per Common Share – Diluted
|
$
|
1.24
|
|
|
$
|
1.54
|
|
|
$
|
1.03
|
|
|
$
|
0.75
|
|
|
|
|
|
|
|
|
|
||||||||
Dividends per Common Share
|
$
|
0.40
|
|
|
$
|
0.40
|
|
|
$
|
1.20
|
|
|
$
|
1.20
|
|
Average Common Shares Outstanding - Basic
|
242.6
|
|
|
242.6
|
|
|
242.6
|
|
|
242.6
|
|
||||
Average Common Shares Outstanding - Diluted
|
245.1
|
|
|
242.9
|
|
|
244.4
|
|
|
242.9
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Income from Continuing Operations
|
$
|
307
|
|
|
$
|
311
|
|
|
$
|
469
|
|
|
$
|
512
|
|
Other Comprehensive Income (Loss), Net of Taxes
|
|
|
|
|
|
|
|
||||||||
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of ($5), $-, $3, and $-, respectively
|
(5
|
)
|
|
—
|
|
|
5
|
|
|
1
|
|
||||
Total other comprehensive income (loss), net of taxes
|
(5
|
)
|
|
—
|
|
|
5
|
|
|
1
|
|
||||
Comprehensive Income from Continuing Operations
|
302
|
|
|
311
|
|
|
474
|
|
|
513
|
|
||||
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests
|
2
|
|
|
2
|
|
|
5
|
|
|
5
|
|
||||
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation
|
300
|
|
|
309
|
|
|
469
|
|
|
508
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Income (Loss) from Discontinued Operations, Net of Taxes
|
(3
|
)
|
|
63
|
|
|
(212
|
)
|
|
(331
|
)
|
||||
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Taxes
|
(5
|
)
|
|
41
|
|
|
(16
|
)
|
|
60
|
|
||||
Comprehensive Income (Loss) from Discontinued Operations
|
(8
|
)
|
|
104
|
|
|
(228
|
)
|
|
(271
|
)
|
||||
Less: Comprehensive Income from Discontinued Operations Attributable to Noncontrolling Interest
|
—
|
|
|
7
|
|
|
—
|
|
|
3
|
|
||||
Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation
|
(8
|
)
|
|
97
|
|
|
(228
|
)
|
|
(274
|
)
|
||||
Comprehensive Income Attributable to Ameren Corporation
|
$
|
292
|
|
|
$
|
406
|
|
|
$
|
241
|
|
|
$
|
234
|
|
|
September 30, 2013
|
|
December 31, 2012
|
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
169
|
|
|
$
|
184
|
|
Accounts receivable – trade (less allowance for doubtful accounts of $20 and $17, respectively)
|
469
|
|
|
354
|
|
||
Unbilled revenue
|
226
|
|
|
291
|
|
||
Miscellaneous accounts and notes receivable
|
109
|
|
|
71
|
|
||
Materials and supplies
|
581
|
|
|
570
|
|
||
Current regulatory assets
|
173
|
|
|
247
|
|
||
Current accumulated deferred income taxes, net
|
43
|
|
|
170
|
|
||
Other current assets
|
108
|
|
|
98
|
|
||
Assets of discontinued operations (Note 2)
|
1,395
|
|
|
1,600
|
|
||
Total current assets
|
3,273
|
|
|
3,585
|
|
||
Property and Plant, Net
|
15,834
|
|
|
15,348
|
|
||
Investments and Other Assets:
|
|
|
|
||||
Nuclear decommissioning trust fund
|
459
|
|
|
408
|
|
||
Goodwill
|
411
|
|
|
411
|
|
||
Intangible assets
|
19
|
|
|
14
|
|
||
Regulatory assets
|
1,729
|
|
|
1,786
|
|
||
Other assets
|
660
|
|
|
667
|
|
||
Total investments and other assets
|
3,278
|
|
|
3,286
|
|
||
TOTAL ASSETS
|
$
|
22,385
|
|
|
$
|
22,219
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Current maturities of long-term debt
|
$
|
884
|
|
|
$
|
355
|
|
Accounts and wages payable
|
414
|
|
|
533
|
|
||
Taxes accrued
|
159
|
|
|
50
|
|
||
Interest accrued
|
120
|
|
|
89
|
|
||
Customer deposits
|
106
|
|
|
107
|
|
||
Mark-to-market derivative liabilities
|
65
|
|
|
92
|
|
||
Current regulatory liabilities
|
149
|
|
|
100
|
|
||
Other current liabilities
|
190
|
|
|
168
|
|
||
Liabilities of discontinued operations (Note 2)
|
1,141
|
|
|
1,166
|
|
||
Total current liabilities
|
3,228
|
|
|
2,660
|
|
||
Long-term Debt, Net
|
5,274
|
|
|
5,802
|
|
||
Deferred Credits and Other Liabilities:
|
|
|
|
||||
Accumulated deferred income taxes, net
|
3,422
|
|
|
3,176
|
|
||
Accumulated deferred investment tax credits
|
65
|
|
|
70
|
|
||
Regulatory liabilities
|
1,703
|
|
|
1,589
|
|
||
Asset retirement obligations
|
392
|
|
|
375
|
|
||
Pension and other postretirement benefits
|
1,042
|
|
|
1,138
|
|
||
Other deferred credits and liabilities
|
534
|
|
|
642
|
|
||
Total deferred credits and other liabilities
|
7,158
|
|
|
6,990
|
|
||
Commitments and Contingencies (Notes 2, 3, 9, 10 and 11)
|
|
|
|
|
|
||
Ameren Corporation 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
|
5,624
|
|
|
5,616
|
|
||
Retained earnings
|
967
|
|
|
1,006
|
|
||
Accumulated other comprehensive loss
|
(19
|
)
|
|
(8
|
)
|
||
Total Ameren Corporation stockholders’ equity
|
6,574
|
|
|
6,616
|
|
||
Noncontrolling Interests
|
151
|
|
|
151
|
|
||
Total equity
|
6,725
|
|
|
6,767
|
|
||
TOTAL LIABILITIES AND EQUITY
|
$
|
22,385
|
|
|
$
|
22,219
|
|
AMEREN CORPORATION
|
|||||||
CONSOLIDATED STATEMENT OF CASH FLOWS
|
|||||||
(Unaudited) (In millions)
|
|||||||
|
Nine Months Ended September 30,
|
||||||
|
2013
|
|
2012
|
||||
Cash Flows From Operating Activities:
|
|
|
|
||||
Net income
|
$
|
257
|
|
|
$
|
181
|
|
Loss from discontinued operations, net of taxes
|
212
|
|
|
331
|
|
||
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation and amortization
|
500
|
|
|
466
|
|
||
Amortization of nuclear fuel
|
46
|
|
|
63
|
|
||
Amortization of debt issuance costs and premium/discounts
|
18
|
|
|
13
|
|
||
Deferred income taxes and investment tax credits, net
|
258
|
|
|
249
|
|
||
Allowance for equity funds used during construction
|
(26
|
)
|
|
(26
|
)
|
||
Stock-based compensation costs
|
19
|
|
|
23
|
|
||
Other
|
14
|
|
|
(6
|
)
|
||
Changes in assets and liabilities:
|
|
|
|
||||
Receivables
|
(88
|
)
|
|
(21
|
)
|
||
Materials and supplies
|
7
|
|
|
(57
|
)
|
||
Accounts and wages payable
|
(102
|
)
|
|
(157
|
)
|
||
Taxes accrued
|
104
|
|
|
95
|
|
||
Assets, other
|
20
|
|
|
(24
|
)
|
||
Liabilities, other
|
(24
|
)
|
|
61
|
|
||
Pension and other postretirement benefits
|
(34
|
)
|
|
16
|
|
||
Counterparty collateral, net
|
34
|
|
|
21
|
|
||
Premiums paid on long-term debt repurchases
|
—
|
|
|
(138
|
)
|
||
Net cash provided by operating activities - continuing operations
|
1,215
|
|
|
1,090
|
|
||
Net cash provided by operating activities - discontinued operations
|
99
|
|
|
222
|
|
||
Net cash provided by operating activities
|
1,314
|
|
|
1,312
|
|
||
Cash Flows From Investing Activities:
|
|
|
|
||||
Capital expenditures
|
(943
|
)
|
|
(762
|
)
|
||
Nuclear fuel expenditures
|
(34
|
)
|
|
(56
|
)
|
||
Purchases of securities – nuclear decommissioning trust fund
|
(147
|
)
|
|
(341
|
)
|
||
Sales and maturities of securities – nuclear decommissioning trust fund
|
134
|
|
|
326
|
|
||
Other
|
(1
|
)
|
|
(6
|
)
|
||
Net cash used in investing activities - continuing operations
|
(991
|
)
|
|
(839
|
)
|
||
Net cash used in investing activities - discontinued operations
|
(42
|
)
|
|
(123
|
)
|
||
Net cash used in investing activities
|
(1,033
|
)
|
|
(962
|
)
|
||
Cash Flows From Financing Activities:
|
|
|
|
||||
Dividends on common stock
|
(291
|
)
|
|
(284
|
)
|
||
Dividends paid to noncontrolling interest holders
|
(5
|
)
|
|
(5
|
)
|
||
Short-term debt, net
|
—
|
|
|
(143
|
)
|
||
Redemptions, repurchases, and maturities of long-term debt
|
—
|
|
|
(754
|
)
|
||
Issuances of long-term debt
|
—
|
|
|
882
|
|
||
Capital issuance costs
|
—
|
|
|
(7
|
)
|
||
Other
|
—
|
|
|
4
|
|
||
Net cash used in financing activities - continuing operations
|
(296
|
)
|
|
(307
|
)
|
||
Net cash used in financing activities - discontinued operations
|
—
|
|
|
—
|
|
||
Net cash used in financing activities
|
(296
|
)
|
|
(307
|
)
|
||
Net change in cash and cash equivalents
|
(15
|
)
|
|
43
|
|
||
Cash and cash equivalents at beginning of year
|
209
|
|
|
255
|
|
||
Cash and cash equivalents at end of period
|
194
|
|
|
298
|
|
||
Less cash and cash equivalents at end of period, discontinued operations
|
25
|
|
|
25
|
|
||
Cash and cash equivalents at end of period, continuing operations
|
$
|
169
|
|
|
$
|
273
|
|
|
|
|
|
||||
Noncash financing activity – dividends on common stock
|
$
|
—
|
|
|
$
|
(7
|
)
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Operating Revenues:
|
|
|
|
|
|
|
|
||||||||
Electric
|
$
|
1,075
|
|
|
$
|
1,046
|
|
|
$
|
2,667
|
|
|
$
|
2,504
|
|
Gas
|
17
|
|
|
18
|
|
|
110
|
|
|
94
|
|
||||
Other
|
1
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
Total operating revenues
|
1,093
|
|
|
1,064
|
|
|
2,778
|
|
|
2,599
|
|
||||
Operating Expenses:
|
|
|
|
|
|
|
|
||||||||
Fuel
|
222
|
|
|
192
|
|
|
648
|
|
|
549
|
|
||||
Purchased power
|
33
|
|
|
37
|
|
|
100
|
|
|
57
|
|
||||
Gas purchased for resale
|
4
|
|
|
5
|
|
|
52
|
|
|
42
|
|
||||
Other operations and maintenance
|
212
|
|
|
203
|
|
|
686
|
|
|
611
|
|
||||
Depreciation and amortization
|
114
|
|
|
111
|
|
|
338
|
|
|
328
|
|
||||
Taxes other than income taxes
|
91
|
|
|
87
|
|
|
247
|
|
|
236
|
|
||||
Total operating expenses
|
676
|
|
|
635
|
|
|
2,071
|
|
|
1,823
|
|
||||
Operating Income
|
417
|
|
|
429
|
|
|
707
|
|
|
776
|
|
||||
Other Income and Expenses:
|
|
|
|
|
|
|
|
||||||||
Miscellaneous income
|
16
|
|
|
15
|
|
|
44
|
|
|
48
|
|
||||
Miscellaneous expense
|
2
|
|
|
4
|
|
|
10
|
|
|
11
|
|
||||
Total other income
|
14
|
|
|
11
|
|
|
34
|
|
|
37
|
|
||||
Interest Charges
|
43
|
|
|
55
|
|
|
159
|
|
|
167
|
|
||||
Income Before Income Taxes
|
388
|
|
|
385
|
|
|
582
|
|
|
646
|
|
||||
Income Taxes
|
149
|
|
|
148
|
|
|
217
|
|
|
243
|
|
||||
Net Income
|
239
|
|
|
237
|
|
|
365
|
|
|
403
|
|
||||
Other Comprehensive Income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Comprehensive Income
|
$
|
239
|
|
|
$
|
237
|
|
|
$
|
365
|
|
|
$
|
403
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
||||||||
Net Income
|
$
|
239
|
|
|
$
|
237
|
|
|
$
|
365
|
|
|
$
|
403
|
|
Preferred Stock Dividends
|
1
|
|
|
1
|
|
|
3
|
|
|
3
|
|
||||
Net Income Available to Common Stockholder
|
$
|
238
|
|
|
$
|
236
|
|
|
$
|
362
|
|
|
$
|
400
|
|
|
September 30, 2013
|
|
December 31, 2012
|
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
100
|
|
|
$
|
148
|
|
Advances to money pool
|
—
|
|
|
24
|
|
||
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $5, respectively)
|
270
|
|
|
161
|
|
||
Accounts receivable – affiliates
|
9
|
|
|
4
|
|
||
Unbilled revenue
|
151
|
|
|
145
|
|
||
Miscellaneous accounts and notes receivable
|
76
|
|
|
48
|
|
||
Materials and supplies
|
370
|
|
|
397
|
|
||
Current regulatory assets
|
124
|
|
|
163
|
|
||
Other current assets
|
65
|
|
|
69
|
|
||
Total current assets
|
1,165
|
|
|
1,159
|
|
||
Property and Plant, Net
|
10,337
|
|
|
10,161
|
|
||
Investments and Other Assets:
|
|
|
|
||||
Nuclear decommissioning trust fund
|
459
|
|
|
408
|
|
||
Intangible assets
|
19
|
|
|
14
|
|
||
Regulatory assets
|
808
|
|
|
852
|
|
||
Other assets
|
443
|
|
|
449
|
|
||
Total investments and other assets
|
1,729
|
|
|
1,723
|
|
||
TOTAL ASSETS
|
$
|
13,231
|
|
|
$
|
13,043
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Current maturities of long-term debt
|
$
|
309
|
|
|
$
|
205
|
|
Accounts and wages payable
|
186
|
|
|
345
|
|
||
Accounts payable – affiliates
|
61
|
|
|
66
|
|
||
Taxes accrued
|
288
|
|
|
28
|
|
||
Interest accrued
|
67
|
|
|
60
|
|
||
Current regulatory liabilities
|
61
|
|
|
18
|
|
||
Other current liabilities
|
97
|
|
|
77
|
|
||
Total current liabilities
|
1,069
|
|
|
799
|
|
||
Long-term Debt, Net
|
3,697
|
|
|
3,801
|
|
||
Deferred Credits and Other Liabilities:
|
|
|
|
||||
Accumulated deferred income taxes, net
|
2,472
|
|
|
2,443
|
|
||
Accumulated deferred investment tax credits
|
61
|
|
|
64
|
|
||
Regulatory liabilities
|
1,002
|
|
|
917
|
|
||
Asset retirement obligations
|
362
|
|
|
346
|
|
||
Pension and other postretirement benefits
|
423
|
|
|
461
|
|
||
Other deferred credits and liabilities
|
49
|
|
|
158
|
|
||
Total deferred credits and other liabilities
|
4,369
|
|
|
4,389
|
|
||
Commitments and Contingencies (Notes 3, 9, 10 and 11)
|
|
|
|
|
|
||
Stockholders’ Equity:
|
|
|
|
||||
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding
|
511
|
|
|
511
|
|
||
Other paid-in capital, principally premium on common stock
|
1,556
|
|
|
1,556
|
|
||
Preferred stock not subject to mandatory redemption
|
80
|
|
|
80
|
|
||
Retained earnings
|
1,949
|
|
|
1,907
|
|
||
Total stockholders’ equity
|
4,096
|
|
|
4,054
|
|
||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
13,231
|
|
|
$
|
13,043
|
|
|
Nine Months Ended September 30,
|
||||||
|
2013
|
|
2012
|
||||
Cash Flows From Operating Activities:
|
|
|
|
||||
Net income
|
$
|
365
|
|
|
$
|
403
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation and amortization
|
313
|
|
|
303
|
|
||
Amortization of nuclear fuel
|
46
|
|
|
63
|
|
||
FAC prudence review charge
|
26
|
|
|
—
|
|
||
Amortization of debt issuance costs and premium/discounts
|
6
|
|
|
5
|
|
||
Deferred income taxes and investment tax credits, net
|
62
|
|
|
217
|
|
||
Allowance for equity funds used during construction
|
(22
|
)
|
|
(23
|
)
|
||
Other
|
1
|
|
|
7
|
|
||
Changes in assets and liabilities:
|
|
|
|
||||
Receivables
|
(148
|
)
|
|
(62
|
)
|
||
Materials and supplies
|
27
|
|
|
(53
|
)
|
||
Accounts and wages payable
|
(124
|
)
|
|
(168
|
)
|
||
Taxes accrued
|
260
|
|
|
59
|
|
||
Assets, other
|
59
|
|
|
(29
|
)
|
||
Liabilities, other
|
(78
|
)
|
|
22
|
|
||
Pension and other postretirement benefits
|
(12
|
)
|
|
17
|
|
||
Premiums paid on long-term debt repurchases
|
—
|
|
|
(62
|
)
|
||
Net cash provided by operating activities
|
781
|
|
|
699
|
|
||
Cash Flows From Investing Activities:
|
|
|
|
||||
Capital expenditures
|
(480
|
)
|
|
(445
|
)
|
||
Nuclear fuel expenditures
|
(34
|
)
|
|
(56
|
)
|
||
Money pool advances, net
|
24
|
|
|
—
|
|
||
Purchases of securities – nuclear decommissioning trust fund
|
(147
|
)
|
|
(341
|
)
|
||
Sales and maturities of securities – nuclear decommissioning trust fund
|
134
|
|
|
326
|
|
||
Other
|
(3
|
)
|
|
(5
|
)
|
||
Net cash used in investing activities
|
(506
|
)
|
|
(521
|
)
|
||
Cash Flows From Financing Activities:
|
|
|
|
||||
Dividends on common stock
|
(320
|
)
|
|
(300
|
)
|
||
Dividends on preferred stock
|
(3
|
)
|
|
(3
|
)
|
||
Redemptions, repurchases, and maturities of long-term debt
|
—
|
|
|
(422
|
)
|
||
Issuances of long-term debt
|
—
|
|
|
482
|
|
||
Capital issuance costs
|
—
|
|
|
(4
|
)
|
||
Net cash used in financing activities
|
(323
|
)
|
|
(247
|
)
|
||
Net change in cash and cash equivalents
|
(48
|
)
|
|
(69
|
)
|
||
Cash and cash equivalents at beginning of year
|
148
|
|
|
201
|
|
||
Cash and cash equivalents at end of period
|
$
|
100
|
|
|
$
|
132
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Operating Revenues:
|
|
|
|
|
|
|
|
||||||||
Electric
|
$
|
432
|
|
|
$
|
536
|
|
|
$
|
1,160
|
|
|
$
|
1,404
|
|
Gas
|
115
|
|
|
112
|
|
|
585
|
|
|
532
|
|
||||
Other
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
||||
Total operating revenues
|
547
|
|
|
648
|
|
|
1,747
|
|
|
1,936
|
|
||||
Operating Expenses:
|
|
|
|
|
|
|
|
||||||||
Purchased power
|
96
|
|
|
224
|
|
|
303
|
|
|
576
|
|
||||
Gas purchased for resale
|
38
|
|
|
35
|
|
|
292
|
|
|
262
|
|
||||
Other operations and maintenance
|
166
|
|
|
159
|
|
|
538
|
|
|
513
|
|
||||
Depreciation and amortization
|
59
|
|
|
55
|
|
|
182
|
|
|
165
|
|
||||
Taxes other than income taxes
|
30
|
|
|
24
|
|
|
102
|
|
|
94
|
|
||||
Total operating expenses
|
389
|
|
|
497
|
|
|
1,417
|
|
|
1,610
|
|
||||
Operating Income
|
158
|
|
|
151
|
|
|
330
|
|
|
326
|
|
||||
Other Income and Expenses:
|
|
|
|
|
|
|
|
||||||||
Miscellaneous income
|
4
|
|
|
2
|
|
|
7
|
|
|
5
|
|
||||
Miscellaneous expense
|
3
|
|
|
2
|
|
|
7
|
|
|
15
|
|
||||
Total other income (expense)
|
1
|
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
||||
Interest Charges
|
31
|
|
|
34
|
|
|
96
|
|
|
98
|
|
||||
Income Before Income Taxes
|
128
|
|
|
117
|
|
|
234
|
|
|
218
|
|
||||
Income Taxes
|
51
|
|
|
46
|
|
|
93
|
|
|
86
|
|
||||
Net Income
|
77
|
|
|
71
|
|
|
141
|
|
|
132
|
|
||||
Other Comprehensive Loss, Net of Taxes:
|
|
|
|
|
|
|
|
||||||||
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(1), $(1), $(2), and $(2), respectively
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
|
(3
|
)
|
||||
Comprehensive Income
|
$
|
77
|
|
|
$
|
70
|
|
|
$
|
139
|
|
|
$
|
129
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
||||||||
Net Income
|
$
|
77
|
|
|
$
|
71
|
|
|
$
|
141
|
|
|
$
|
132
|
|
Preferred Stock Dividends
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
||||
Net Income Available to Common Stockholder
|
$
|
77
|
|
|
$
|
71
|
|
|
$
|
139
|
|
|
$
|
130
|
|
|
September 30, 2013
|
|
December 31, 2012
|
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
1
|
|
|
$
|
—
|
|
Accounts receivable – trade (less allowance for doubtful accounts of $13 and $12, respectively)
|
185
|
|
|
182
|
|
||
Accounts receivable – affiliates
|
28
|
|
|
10
|
|
||
Unbilled revenue
|
75
|
|
|
146
|
|
||
Miscellaneous accounts receivable
|
8
|
|
|
22
|
|
||
Materials and supplies
|
211
|
|
|
173
|
|
||
Current regulatory assets
|
49
|
|
|
84
|
|
||
Current accumulated deferred income taxes, net
|
35
|
|
|
85
|
|
||
Other current assets
|
33
|
|
|
47
|
|
||
Total current assets
|
625
|
|
|
749
|
|
||
Property and Plant, Net
|
5,369
|
|
|
5,052
|
|
||
Investments and Other Assets:
|
|
|
|
||||
Tax receivable – Genco
|
37
|
|
|
39
|
|
||
Goodwill
|
411
|
|
|
411
|
|
||
Regulatory assets
|
916
|
|
|
934
|
|
||
Other assets
|
81
|
|
|
97
|
|
||
Total investments and other assets
|
1,445
|
|
|
1,481
|
|
||
TOTAL ASSETS
|
$
|
7,439
|
|
|
$
|
7,282
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Current maturities of long-term debt
|
$
|
150
|
|
|
$
|
150
|
|
Borrowings from money pool
|
21
|
|
|
24
|
|
||
Accounts and wages payable
|
189
|
|
|
146
|
|
||
Accounts payable – affiliates
|
86
|
|
|
86
|
|
||
Taxes accrued
|
17
|
|
|
18
|
|
||
Customer deposits
|
81
|
|
|
85
|
|
||
Mark-to-market derivative liabilities
|
48
|
|
|
77
|
|
||
Current environmental remediation
|
53
|
|
|
37
|
|
||
Current regulatory liabilities
|
88
|
|
|
82
|
|
||
Other current liabilities
|
114
|
|
|
92
|
|
||
Total current liabilities
|
847
|
|
|
797
|
|
||
Long-term Debt, Net
|
1,577
|
|
|
1,577
|
|
||
Deferred Credits and Other Liabilities:
|
|
|
|
||||
Accumulated deferred income taxes, net
|
1,095
|
|
|
1,025
|
|
||
Accumulated deferred investment tax credits
|
4
|
|
|
5
|
|
||
Regulatory liabilities
|
701
|
|
|
672
|
|
||
Pension and other postretirement benefits
|
376
|
|
|
406
|
|
||
Environmental remediation
|
194
|
|
|
216
|
|
||
Other deferred credits and liabilities
|
152
|
|
|
183
|
|
||
Total deferred credits and other liabilities
|
2,522
|
|
|
2,507
|
|
||
Commitments and Contingencies (Notes 3, 9 and 10)
|
|
|
|
|
|
||
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
|
454
|
|
|
360
|
|
||
Accumulated other comprehensive income
|
12
|
|
|
14
|
|
||
Total stockholders’ equity
|
2,493
|
|
|
2,401
|
|
||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
7,439
|
|
|
$
|
7,282
|
|
|
Nine Months Ended September 30,
|
||||||
|
2013
|
|
2012
|
||||
Cash Flows From Operating Activities:
|
|
|
|
||||
Net income
|
$
|
141
|
|
|
$
|
132
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation and amortization
|
178
|
|
|
159
|
|
||
Amortization of debt issuance costs and premium/discounts
|
11
|
|
|
7
|
|
||
Deferred income taxes and investment tax credits, net
|
120
|
|
|
127
|
|
||
Other
|
(7
|
)
|
|
(8
|
)
|
||
Changes in assets and liabilities:
|
|
|
|
||||
Receivables
|
66
|
|
|
58
|
|
||
Materials and supplies
|
(20
|
)
|
|
(6
|
)
|
||
Accounts and wages payable
|
31
|
|
|
(4
|
)
|
||
Taxes accrued
|
(2
|
)
|
|
(3
|
)
|
||
Assets, other
|
(33
|
)
|
|
(2
|
)
|
||
Liabilities, other
|
1
|
|
|
42
|
|
||
Pension and other postretirement benefits
|
(13
|
)
|
|
(8
|
)
|
||
Counterparty collateral, net
|
34
|
|
|
23
|
|
||
Premiums paid on long-term debt repurchases
|
—
|
|
|
(76
|
)
|
||
Net cash provided by operating activities
|
507
|
|
|
441
|
|
||
Cash Flows From Investing Activities:
|
|
|
|
||||
Capital expenditures
|
(462
|
)
|
|
(309
|
)
|
||
Other
|
6
|
|
|
5
|
|
||
Net cash used in investing activities
|
(456
|
)
|
|
(304
|
)
|
||
Cash Flows From Financing Activities:
|
|
|
|
||||
Dividends on common stock
|
(45
|
)
|
|
(132
|
)
|
||
Dividends on preferred stock
|
(2
|
)
|
|
(2
|
)
|
||
Money pool borrowings, net
|
(3
|
)
|
|
—
|
|
||
Redemptions, repurchases, and maturities on long-term debt
|
—
|
|
|
(332
|
)
|
||
Issuances of long-term debt
|
—
|
|
|
400
|
|
||
Capital issuance costs
|
—
|
|
|
(3
|
)
|
||
Other
|
—
|
|
|
4
|
|
||
Net cash used in financing activities
|
(50
|
)
|
|
(65
|
)
|
||
Net change in cash and cash equivalents
|
1
|
|
|
72
|
|
||
Cash and cash equivalents at beginning of year
|
—
|
|
|
21
|
|
||
Cash and cash equivalents at end of period
|
$
|
1
|
|
|
$
|
93
|
|
•
|
Union Electric Company, doing 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 Illinois Company, doing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
|
•
|
AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company, and, through Genco, an
80%
ownership interest in EEI, which Ameren consolidates for financial reporting purposes.
|
|
Three Months
|
|
Nine Months
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Net income (loss) attributable to Ameren Corporation:
|
|
|
|
|
|
|
|
||||||||
Continuing operations
|
$
|
305
|
|
|
$
|
309
|
|
|
$
|
464
|
|
|
$
|
507
|
|
Discontinued operations
|
(3
|
)
|
|
65
|
|
|
(212
|
)
|
|
(325
|
)
|
||||
Net income (loss) attributable to Ameren Corporation
|
$
|
302
|
|
|
$
|
374
|
|
|
$
|
252
|
|
|
$
|
182
|
|
|
|
|
|
|
|
|
|
||||||||
Average common shares outstanding - basic
|
242.6
|
|
|
242.6
|
|
|
242.6
|
|
|
242.6
|
|
||||
Assumed settlement of performance share units
|
2.5
|
|
|
0.3
|
|
|
1.8
|
|
|
0.3
|
|
||||
Average common shares outstanding - diluted
|
245.1
|
|
|
242.9
|
|
|
244.4
|
|
|
242.9
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Earnings (loss) per common share – basic:
|
|
|
|
|
|
|
|
||||||||
Continuing operations
|
$
|
1.26
|
|
|
$
|
1.28
|
|
|
$
|
1.92
|
|
|
$
|
2.09
|
|
Discontinued operations
|
(0.01
|
)
|
|
0.26
|
|
|
(0.88
|
)
|
|
(1.34
|
)
|
||||
Earnings (loss) per common share – basic
|
$
|
1.25
|
|
|
$
|
1.54
|
|
|
$
|
1.04
|
|
|
$
|
0.75
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings (loss) per common share – diluted:
|
|
|
|
|
|
|
|
||||||||
Continuing operations
|
$
|
1.25
|
|
|
$
|
1.28
|
|
|
$
|
1.91
|
|
|
$
|
2.09
|
|
Discontinued operations
|
(0.01
|
)
|
|
0.26
|
|
|
(0.88
|
)
|
|
(1.34
|
)
|
||||
Earnings (loss) per common share – diluted
|
$
|
1.24
|
|
|
$
|
1.54
|
|
|
$
|
1.03
|
|
|
$
|
0.75
|
|
|
|
|
|
|
|
|
|
||||||||
Average performance share units excluded from calculation
(a)
|
—
|
|
|
1.0
|
|
|
0.1
|
|
|
1.0
|
|
(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.
|
|
Performance Share Units
|
||||
|
Share Units
|
Weighted-average Fair Value Per Unit at Grant Date
|
|||
Nonvested as of January 1, 2013
|
1,192,487
|
|
$
|
33.56
|
|
Granted
(a)
|
837,199
|
|
31.19
|
|
|
Forfeitures
|
(7,757
|
)
|
32.66
|
|
|
Vested
(b)
|
(131,960
|
)
|
31.30
|
|
|
Nonvested as of September 30, 2013
|
1,889,969
|
|
$
|
32.67
|
|
(a)
|
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2013 under the 2006 Plan.
|
(b)
|
Share units vested due to the attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the
three
-year measurement period.
|
|
|
Three Months
|
|
Nine Months
|
|||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Ameren Missouri
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
(a)
|
|
|
$
|
1
|
|
Ameren Illinois
|
|
2
|
|
|
|
1
|
|
|
|
9
|
|
|
|
1
|
|
Ameren
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
9
|
|
|
$
|
2
|
|
(a)
|
Less than $1 million.
|
|
Three Months
|
|
Nine Months
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Ameren Missouri
|
$
|
49
|
|
|
$
|
46
|
|
|
$
|
120
|
|
|
$
|
111
|
|
Ameren Illinois
|
10
|
|
|
9
|
|
|
43
|
|
|
37
|
|
||||
Ameren
|
$
|
59
|
|
|
$
|
55
|
|
|
$
|
163
|
|
|
$
|
148
|
|
|
Ameren
Missouri
(a)
|
|
Ameren
Illinois
(b)
|
|
Other
(c)
|
|
Ameren
(a)
|
|
||||||||
Balance at December 31, 2012
|
$
|
346
|
|
|
$
|
3
|
|
|
$
|
26
|
|
|
$
|
375
|
|
|
Liabilities incurred
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
||||
Liabilities settled
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
||||
Accretion in 2013
(e)
|
14
|
|
|
(d)
|
|
|
1
|
|
|
15
|
|
|
||||
Change in estimates
(f)
|
2
|
|
|
(d)
|
|
|
(d)
|
|
|
2
|
|
|
||||
Balance at September 30, 2013
|
$
|
362
|
|
|
$
|
3
|
|
|
$
|
27
|
|
|
$
|
392
|
|
|
(a)
|
The nuclear decommissioning trust fund assets of
$459 million
and
$408 million
as of
September 30, 2013
, and December 31,
2012
, respectively, were restricted for decommissioning of the Callaway energy center.
|
(b)
|
Balance included in “Other deferred credits and liabilities” on the balance sheet.
|
(c)
|
Represents amounts for the Meredosia and Hutsonville energy centers. Pursuant to the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
|
(d)
|
Less than $1 million.
|
(e)
|
Accretion was recorded as an increase to regulatory assets at Ameren Missouri and Ameren Illinois.
|
(f)
|
Ameren Missouri changed its fair value estimates for asbestos removal and certain CCR storage facilities.
|
|
Three Months
|
|
Nine Months
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Noncontrolling interests, beginning of period
(a)
|
$
|
151
|
|
|
$
|
145
|
|
|
$
|
151
|
|
|
$
|
149
|
|
Net income from continuing operations attributable to noncontrolling interests
|
2
|
|
|
2
|
|
|
5
|
|
|
5
|
|
||||
Net loss from discontinued operations attributable to noncontrolling interests
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(6
|
)
|
||||
Dividends paid to noncontrolling interest holders
|
(2
|
)
|
|
(2
|
)
|
|
(5
|
)
|
|
(5
|
)
|
||||
Other comprehensive income attributable to noncontrolling interests
(b)
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||
Noncontrolling interests, end of period
(a)
|
$
|
151
|
|
|
$
|
152
|
|
|
$
|
151
|
|
|
$
|
152
|
|
(a)
|
Includes the
20%
EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations.” The 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s
September 30, 2013
, and December 31, 2012 balance sheets. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
|
(b)
|
Represents the noncontrolling interest of EEI’s pension and other postretirement benefit plan activity, net of income taxes of $-,
$6
, $-, and
$6
, respectively.
|
|
Three Months
|
|
Nine months
|
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
||||||||
Operating revenues
|
$
|
311
|
|
|
$
|
293
|
|
|
$
|
878
|
|
|
$
|
797
|
|
|
Operating expenses
|
(309
|
)
|
|
(237
|
)
|
|
(1,034
|
)
|
(a)
|
(1,301
|
)
|
(b)
|
||||
Operating income (loss)
|
2
|
|
|
56
|
|
|
(156
|
)
|
|
(504
|
)
|
|
||||
Other income (loss)
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
||||
Interest charges
|
(9
|
)
|
|
(14
|
)
|
|
(31
|
)
|
|
(43
|
)
|
|
||||
Income (loss) before income taxes
|
(7
|
)
|
|
42
|
|
|
(188
|
)
|
|
(547
|
)
|
|
||||
Income tax (expense) benefit
|
4
|
|
|
21
|
|
|
(24
|
)
|
|
216
|
|
|
||||
Income (loss) from discontinued operations, net of taxes
|
$
|
(3
|
)
|
|
$
|
63
|
|
|
$
|
(212
|
)
|
|
$
|
(331
|
)
|
|
(a)
|
Includes a noncash pretax impairment charge of
$175 million
for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.
|
(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 used accounting guidance.
|
|
September 30, 2013
|
|
December 31, 2012
|
||||
Assets of discontinued operations
|
|
|
|
||||
Cash and cash equivalents
|
$
|
25
|
|
|
$
|
25
|
|
Accounts receivable and unbilled revenue
|
102
|
|
|
102
|
|
||
Materials and supplies
|
121
|
|
|
134
|
|
||
Mark-to-market derivative assets
|
71
|
|
|
102
|
|
||
Property and plant, net
|
623
|
|
|
748
|
|
||
Accumulated deferred income taxes, net
|
357
|
|
|
385
|
|
||
Other assets
|
96
|
|
|
104
|
|
||
Total assets of discontinued operations
|
$
|
1,395
|
|
|
$
|
1,600
|
|
Liabilities of discontinued operations
|
|
|
|
||||
Accounts payable and other current obligations
|
$
|
141
|
|
|
$
|
133
|
|
Mark-to-market derivative liabilities
|
38
|
|
|
63
|
|
||
Long-term debt, net
|
824
|
|
|
824
|
|
||
Asset retirement obligations
|
87
|
|
|
78
|
|
||
Pension and other postretirement benefits
|
32
|
|
|
40
|
|
||
Other liabilities
|
19
|
|
|
28
|
|
||
Total liabilities of discontinued operations
|
$
|
1,141
|
|
|
$
|
1,166
|
|
Accumulated other comprehensive income
(a)
|
$
|
3
|
|
|
$
|
19
|
|
Noncontrolling interest
(b)
|
$
|
8
|
|
|
$
|
8
|
|
(a)
|
Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s
September 30, 2013
, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.
|
(b)
|
The
20%
ownership interest of EEI not owned by Ameren was included in “Noncontrolling interests” on Ameren’s
September 30, 2013
, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.
|
|
Required
Ratio
|
Actual
Ratio
|
|
Interest coverage ratio- restricted payment
(a)
|
≥1.75
|
1.05
|
|
Interest coverage ratio- additional indebtedness
(b)
|
≥2.50
|
1.05
|
|
Debt-to-capital ratio- additional indebtedness
(b)
|
≤60%
|
51
|
%
|
(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.
|
|
|
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
|
|
4.3
|
$
|
3,564
|
|
|
≥2.5
|
|
111.5
|
$
|
2,130
|
|
Ameren Illinois
|
|
≥2.0
|
|
7.4
|
|
3,536
|
|
(d)
|
≥1.5
|
|
2.7
|
|
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
$485 million
and
$645 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.
|
|
Three Months
|
|
Nine Months
|
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
||||||||
Ameren:
(a)
|
|
|
|
|
|
|
|
|
||||||||
Miscellaneous income:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for equity funds used during construction
|
$
|
10
|
|
|
$
|
9
|
|
|
$
|
26
|
|
|
$
|
26
|
|
|
Interest income on industrial development revenue bonds
|
7
|
|
|
7
|
|
|
21
|
|
|
21
|
|
|
||||
Interest and dividend income
|
2
|
|
|
—
|
|
|
3
|
|
|
4
|
|
(b)
|
||||
Other
|
1
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
||||
Total miscellaneous income
|
$
|
20
|
|
|
$
|
17
|
|
|
$
|
51
|
|
|
$
|
53
|
|
|
Miscellaneous expense:
|
|
|
|
|
|
|
|
|
||||||||
Donations
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
7
|
|
|
$
|
18
|
|
(c)
|
Other
|
3
|
|
|
3
|
|
|
11
|
|
|
10
|
|
|
||||
Total miscellaneous expense
|
$
|
5
|
|
|
$
|
6
|
|
|
$
|
18
|
|
|
$
|
28
|
|
|
Ameren Missouri:
|
|
|
|
|
|
|
|
|
||||||||
Miscellaneous income:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for equity funds used during construction
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
22
|
|
|
$
|
23
|
|
|
Interest income on industrial development revenue bonds
|
7
|
|
|
7
|
|
|
21
|
|
|
21
|
|
|
||||
Interest and dividend income
|
1
|
|
|
—
|
|
|
1
|
|
|
4
|
|
(b)
|
||||
Total miscellaneous income
|
$
|
16
|
|
|
$
|
15
|
|
|
$
|
44
|
|
|
$
|
48
|
|
|
Miscellaneous expense:
|
|
|
|
|
|
|
|
|
||||||||
Donations
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
7
|
|
|
Other
|
2
|
|
|
2
|
|
|
7
|
|
|
4
|
|
|
||||
Total miscellaneous expense
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
10
|
|
|
$
|
11
|
|
|
Ameren Illinois:
|
|
|
|
|
|
|
|
|
||||||||
Miscellaneous income:
|
|
|
|
|
|
|
|
|
||||||||
Allowance for equity funds used during construction
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
Interest and dividend income
|
1
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
||||
Other
|
1
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|
||||
Total miscellaneous income
|
$
|
4
|
|
|
$
|
2
|
|
|
$
|
7
|
|
|
$
|
5
|
|
|
Miscellaneous expense:
|
|
|
|
|
|
|
|
|
||||||||
Donations
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
3
|
|
|
$
|
11
|
|
(c)
|
Other
|
3
|
|
|
1
|
|
|
4
|
|
|
4
|
|
|
||||
Total miscellaneous expense
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
7
|
|
|
$
|
15
|
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
(b)
|
Includes interest income received in 2012 relating to a refund of charges included in an expired power purchase agreement with Entergy.
|
(c)
|
Includes Ameren Illinois’ one-time
$7.5 million
contribution to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 election to participate in the formula ratemaking process.
|
•
|
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.
|
|
Quantity (in millions, except as indicated)
|
||||||||||||||||
Commodity
|
Accrual & NPNS
Contracts
(a)
|
|
Other
Derivatives
(b)
|
|
Derivatives That Qualify
for Regulatory Deferral
(c)
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||
Coal (in tons)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Ameren Missouri & Ameren
|
81
|
|
|
96
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
Fuel oils (in gallons)
(e)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Ameren Missouri & Ameren
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
60
|
|
|
70
|
|
Natural gas (in mmbtu)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Ameren Missouri
|
2
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|
19
|
|
Ameren Illinois
|
6
|
|
|
16
|
|
|
(d)
|
|
|
(d)
|
|
|
115
|
|
|
128
|
|
Ameren
|
8
|
|
|
20
|
|
|
—
|
|
|
—
|
|
|
144
|
|
|
147
|
|
Power (in megawatthours)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Ameren Missouri
|
3
|
|
|
3
|
|
|
1
|
|
|
2
|
|
|
5
|
|
|
9
|
|
Ameren Illinois
|
15
|
|
|
21
|
|
|
(d)
|
|
|
(d)
|
|
|
11
|
|
|
14
|
|
Ameren
|
18
|
|
|
24
|
|
|
1
|
|
|
2
|
|
|
16
|
|
|
23
|
|
Renewable energy credits
(f)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Ameren Missouri
|
3
|
|
|
3
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
Ameren Illinois
|
11
|
|
|
12
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
Ameren
|
14
|
|
|
15
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
|
(d)
|
|
Uranium (pounds in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Ameren Missouri & Ameren
|
4,516
|
|
|
5,142
|
|
|
(d)
|
|
|
(d)
|
|
|
996
|
|
|
446
|
|
(a)
|
Accrual contracts include commodity contracts that do not qualify as derivatives. As of
September 30, 2013
, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.
|
(b)
|
As of
September 30, 2013
, these contracts ran through December 2014 for power.
|
(c)
|
As of
September 30, 2013
, these contracts ran through October 2015, October 2019, May 2032, and October 2016 for fuel oils, natural gas, power, and uranium, respectively.
|
(d)
|
Not applicable.
|
(e)
|
Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.
|
(f)
|
A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power.
|
(a)
|
Includes derivatives subject to regulatory deferral.
|
(b)
|
Balance sheet line item not applicable to registrant.
|
|
Ameren
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
||||||
2013
|
|
|
|
|
|
||||||
Cumulative gains (losses) deferred in regulatory liabilities or assets:
|
|
|
|
|
|
||||||
Fuel oils derivative contracts
(a)
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
—
|
|
Natural gas derivative contracts
(b)
|
(74
|
)
|
|
(12
|
)
|
|
(62
|
)
|
|||
Power derivative contracts
(c)
|
(67
|
)
|
|
27
|
|
|
(94
|
)
|
|||
Uranium derivative contracts
(d)
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|||
2012
|
|
|
|
|
|
||||||
Cumulative gains (losses) deferred in regulatory liabilities or assets:
|
|
|
|
|
|
||||||
Fuel oils derivative contracts
(a)
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
—
|
|
Natural gas derivative contracts
(b)
|
(107
|
)
|
|
(14
|
)
|
|
(93
|
)
|
|||
Power derivative contracts
(c)
|
(99
|
)
|
|
12
|
|
|
(111
|
)
|
|||
Uranium derivative contracts
(d)
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
(a)
|
Represents net gains (losses) on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through October 2015 as of
September 30, 2013
. Current gains deferred as regulatory liabilities include
$3 million
and
$3 million
at Ameren and Ameren Missouri, respectively, as of
September 30, 2013
. Current losses deferred as regulatory assets include
$1 million
and
$1 million
at Ameren and Ameren Missouri, respectively, as of
September 30, 2013
.
|
(b)
|
Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through March 2017 at Ameren Illinois as of
September 30, 2013
. Current gains deferred as regulatory liabilities include
$1 million
, and
$1 million
at Ameren and Ameren Missouri, respectively, as of
September 30, 2013
. Current losses deferred as regulatory assets include
$45 million
,
$7 million
, and
$38 million
at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of
September 30, 2013
.
|
(c)
|
Represents net gains (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 as of
September 30, 2013
. Current gains deferred as regulatory liabilities include
$29 million
and
$29 million
at Ameren and Ameren Missouri, respectively, as of
September 30, 2013
. Current losses deferred as regulatory assets include
$13 million
,
$3 million
, and
$10 million
at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of
September 30, 2013
.
|
(d)
|
Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through October 2016 as of
September 30, 2013
. Current gains deferred as regulatory liabilities included
$1 million
and
$1 million
at Ameren and Ameren Missouri, respectively, as of September 30, 2013. Current losses deferred as regulatory assets include
$4 million
and
$4 million
at Ameren and Ameren Missouri, respectively, as of
September 30, 2013
.
|
|
|
|
|
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
|
|
$
|
41
|
|
|
$
|
11
|
|
|
$
|
—
|
|
|
$
|
30
|
|
Ameren Missouri
|
|
41
|
|
|
11
|
|
|
—
|
|
|
30
|
|
||||
Ameren Illinois
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Liabilities:
|
|
|
|
|
|
|
|
|
||||||||
Ameren
|
|
$
|
182
|
|
|
$
|
11
|
|
|
$
|
32
|
|
|
$
|
139
|
|
Ameren Missouri
|
|
26
|
|
|
11
|
|
|
8
|
|
|
7
|
|
||||
Ameren Illinois
|
|
156
|
|
|
—
|
|
|
24
|
|
|
132
|
|
||||
2012
|
|
|
|
|
|
|
|
|
||||||||
Commodity contracts eligible to be offset:
|
|
|
|
|
|
|
|
|
||||||||
Assets:
|
|
|
|
|
|
|
|
|
||||||||
Ameren
|
|
$
|
29
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
19
|
|
Ameren Missouri
|
|
28
|
|
|
9
|
|
|
—
|
|
|
19
|
|
||||
Ameren Illinois
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Liabilities:
|
|
|
|
|
|
|
|
|
||||||||
Ameren
|
|
$
|
230
|
|
|
$
|
10
|
|
|
$
|
65
|
|
|
$
|
155
|
|
Ameren Missouri
|
|
25
|
|
|
9
|
|
|
7
|
|
|
9
|
|
||||
Ameren Illinois
|
|
205
|
|
|
1
|
|
|
58
|
|
|
146
|
|
(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.
|
|
Commodity
Marketing
Companies
|
|
Electric
Utilities
|
|
Financial
Companies
|
|
Municipalities/
Cooperatives
|
|
Total
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
||||||||||
Ameren Missouri
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
7
|
|
|
$
|
2
|
|
|
$
|
11
|
|
Ameren Illinois
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Ameren
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
7
|
|
|
$
|
2
|
|
|
$
|
11
|
|
2012
|
|
|
|
|
|
|
|
|
|
||||||||||
Ameren Missouri
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
14
|
|
|
$
|
3
|
|
|
$
|
22
|
|
Ameren Illinois
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|||||
Ameren
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
15
|
|
|
$
|
3
|
|
|
$
|
23
|
|
|
Commodity
Marketing
Companies
|
|
Electric
Utilities
|
|
Financial
Companies
|
|
Municipalities/
Cooperatives
|
|
Total
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
||||||||||
Ameren Missouri
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
5
|
|
Ameren Illinois
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Ameren
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
5
|
|
2012
|
|
|
|
|
|
|
|
|
|
||||||||||
Ameren Missouri
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
10
|
|
|
$
|
3
|
|
|
$
|
15
|
|
Ameren Illinois
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Ameren
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
10
|
|
|
$
|
3
|
|
|
$
|
15
|
|
|
Aggregate Fair Value of
Derivative Liabilities
(a)
|
|
Cash
Collateral Posted
|
|
Potential Aggregate Amount of
Additional Collateral Required
(b)
|
||||||
2013
|
|
|
|
|
|
||||||
Ameren Missouri
|
$
|
69
|
|
|
$
|
1
|
|
|
$
|
63
|
|
Ameren Illinois
|
101
|
|
|
24
|
|
|
70
|
|
|||
Ameren
|
$
|
170
|
|
|
$
|
25
|
|
|
$
|
133
|
|
2012
|
|
|
|
|
|
||||||
Ameren Missouri
|
$
|
78
|
|
|
$
|
3
|
|
|
$
|
71
|
|
Ameren Illinois
|
148
|
|
|
58
|
|
|
84
|
|
|||
Ameren
|
$
|
226
|
|
|
$
|
61
|
|
|
$
|
155
|
|
(a)
|
Prior to consideration of master trading and netting agreements and including NPNS 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 netting effects of such agreements.
|
|
|
|
Gain (Loss) Recognized in Regulatory Liabilities or Regulatory Assets
|
||||||||||||||
|
|
|
Three Months
|
|
Nine Months
|
||||||||||||
|
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Ameren
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
5
|
|
|
$
|
(3
|
)
|
|
$
|
(9
|
)
|
|
Natural gas
|
|
9
|
|
|
46
|
|
|
33
|
|
|
74
|
|
||||
|
Power
(a)
|
|
(24
|
)
|
|
(6
|
)
|
|
32
|
|
|
(169
|
)
|
||||
|
Uranium
|
|
(2
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|
(1
|
)
|
||||
|
Total
|
|
$
|
(16
|
)
|
|
$
|
44
|
|
|
$
|
59
|
|
|
$
|
(105
|
)
|
Ameren Missouri
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
5
|
|
|
$
|
(3
|
)
|
|
$
|
(9
|
)
|
|
Natural gas
|
|
—
|
|
|
6
|
|
|
2
|
|
|
9
|
|
||||
|
Power
|
|
(10
|
)
|
|
(6
|
)
|
|
15
|
|
|
(3
|
)
|
||||
|
Uranium
|
|
(2
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|
(1
|
)
|
||||
|
Total
|
|
$
|
(11
|
)
|
|
$
|
4
|
|
|
$
|
11
|
|
|
$
|
(4
|
)
|
Ameren Illinois
|
Natural gas
|
|
$
|
9
|
|
|
$
|
40
|
|
|
$
|
31
|
|
|
$
|
65
|
|
|
Power
|
|
(14
|
)
|
|
56
|
|
|
17
|
|
|
(25
|
)
|
||||
|
Total
|
|
$
|
(5
|
)
|
|
$
|
96
|
|
|
$
|
48
|
|
|
$
|
40
|
|
(a)
|
Amounts include intercompany eliminations.
|
(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.
|
(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 only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances.
|
(e)
|
Not applicable.
|
(f)
|
Power valuations utilize visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.
|
(g)
|
Escalation rate applies to power prices 2026 and beyond.
|
(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.
|
(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 only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances.
|
(e)
|
Not applicable.
|
(f)
|
Power valuations utilize visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.
|
|
|
|
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
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
$
|
8
|
|
|
Natural gas
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
|
Power
|
|
—
|
|
|
2
|
|
|
29
|
|
|
31
|
|
||||
|
Uranium
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
|
Total derivative assets - commodity contracts
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
38
|
|
|
$
|
41
|
|
|
Nuclear Decommissioning Trust Fund
(b)
:
|
|
|
|
|
|
|
|
|
||||||||
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
||||||||
|
U.S. large capitalization
|
|
309
|
|
|
—
|
|
|
—
|
|
|
309
|
|
||||
|
Debt securities:
|
|
|
|
|
|
|
|
|
||||||||
|
Corporate bonds
|
|
—
|
|
|
45
|
|
|
—
|
|
|
45
|
|
||||
|
Municipal bonds
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
||||
|
U.S. treasury and agency securities
|
|
—
|
|
|
90
|
|
|
—
|
|
|
90
|
|
||||
|
Asset-backed securities
|
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||
|
Other
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
|
Total Nuclear Decommissioning Trust Fund
|
|
$
|
311
|
|
|
$
|
147
|
|
|
$
|
—
|
|
|
$
|
458
|
|
|
Total Ameren
|
|
$
|
312
|
|
|
$
|
149
|
|
|
$
|
38
|
|
|
$
|
499
|
|
Ameren
|
Derivative assets - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Missouri
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
$
|
8
|
|
|
Natural gas
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
|
Power
|
|
—
|
|
|
2
|
|
|
29
|
|
|
31
|
|
||||
|
Uranium
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
|
Total derivative assets - commodity contracts
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
38
|
|
|
$
|
41
|
|
|
Nuclear Decommissioning Trust Fund
(b)
:
|
|
|
|
|
|
|
|
|
||||||||
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
||||||||
|
U.S. large capitalization
|
|
309
|
|
|
—
|
|
|
—
|
|
|
309
|
|
||||
|
Debt securities:
|
|
|
|
|
|
|
|
|
||||||||
|
Corporate bonds
|
|
—
|
|
|
45
|
|
|
—
|
|
|
45
|
|
||||
|
Municipal bonds
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
||||
|
U.S. treasury and agency securities
|
|
—
|
|
|
90
|
|
|
—
|
|
|
90
|
|
||||
|
Asset-backed securities
|
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||
|
Other
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||
|
Total Nuclear Decommissioning Trust Fund
|
|
$
|
311
|
|
|
$
|
147
|
|
|
$
|
—
|
|
|
$
|
458
|
|
|
Total Ameren Missouri
|
|
$
|
312
|
|
|
$
|
149
|
|
|
$
|
38
|
|
|
$
|
499
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||
Ameren
|
Derivative liabilities - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
|
Fuel oils
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
Natural gas
|
|
5
|
|
|
69
|
|
|
1
|
|
|
75
|
|
||||
|
Power
|
|
—
|
|
|
2
|
|
|
95
|
|
|
97
|
|
||||
|
Uranium
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
||||
|
Total Ameren
|
|
$
|
5
|
|
|
$
|
71
|
|
|
$
|
106
|
|
|
$
|
182
|
|
Ameren
|
Derivative liabilities - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Missouri
|
Fuel oils
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
Natural gas
|
|
5
|
|
|
7
|
|
|
1
|
|
|
13
|
|
||||
|
Power
|
|
—
|
|
|
2
|
|
|
1
|
|
|
3
|
|
||||
|
Uranium
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
||||
|
Total Ameren Missouri
|
|
$
|
5
|
|
|
$
|
9
|
|
|
$
|
12
|
|
|
$
|
26
|
|
Ameren
|
Derivative liabilities - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Illinois
|
Natural gas
|
|
$
|
—
|
|
|
$
|
62
|
|
|
$
|
—
|
|
|
$
|
62
|
|
|
Power
|
|
—
|
|
|
—
|
|
|
94
|
|
|
94
|
|
||||
|
Total Ameren Illinois
|
|
$
|
—
|
|
|
$
|
62
|
|
|
$
|
94
|
|
|
$
|
156
|
|
(a)
|
The derivative asset and liability balances are presented net of counterparty credit considerations.
|
(b)
|
Balance excludes $
1 million
of receivables, payables, and accrued income, net.
|
|
|
|
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
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
8
|
|
|
$
|
12
|
|
|
Natural gas
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
||||
|
Power
|
|
—
|
|
|
1
|
|
|
14
|
|
|
15
|
|
||||
|
Total derivative assets - commodity contracts
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
22
|
|
|
$
|
29
|
|
|
Nuclear Decommissioning Trust Fund
(b)
:
|
|
|
|
|
|
|
|
|
||||||||
|
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
|
|
$
|
269
|
|
|
$
|
144
|
|
|
$
|
22
|
|
|
$
|
435
|
|
Ameren
|
Derivative assets - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Missouri
|
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
(b)
:
|
|
|
|
|
|
|
|
|
||||||||
|
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
|
Derivative assets - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Illinois
|
Natural gas
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
|
|
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
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||
Ameren
|
Derivative liabilities - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
4
|
|
|
Natural gas
|
|
7
|
|
|
102
|
|
|
—
|
|
|
109
|
|
||||
|
Power
|
|
—
|
|
|
1
|
|
|
114
|
|
|
115
|
|
||||
|
Uranium
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
||||
|
Total Ameren
|
|
$
|
8
|
|
|
$
|
103
|
|
|
$
|
119
|
|
|
$
|
230
|
|
Ameren
|
Derivative liabilities - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Missouri
|
Fuel oils
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
4
|
|
|
Natural gas
|
|
7
|
|
|
8
|
|
|
—
|
|
|
15
|
|
||||
|
Power
|
|
—
|
|
|
1
|
|
|
3
|
|
|
4
|
|
||||
|
Uranium
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
||||
|
Total Ameren Missouri
|
|
$
|
8
|
|
|
$
|
9
|
|
|
$
|
8
|
|
|
$
|
25
|
|
Ameren
|
Derivative liabilities - commodity contracts
(a)
:
|
|
|
|
|
|
|
|
|
||||||||
Illinois
|
Natural gas
|
|
$
|
—
|
|
|
$
|
94
|
|
|
$
|
—
|
|
|
$
|
94
|
|
|
Power
|
|
—
|
|
|
—
|
|
|
111
|
|
|
111
|
|
||||
|
Total Ameren Illinois
|
|
$
|
—
|
|
|
$
|
94
|
|
|
$
|
111
|
|
|
$
|
205
|
|
(a)
|
The derivative asset and liability balances are presented net of counterparty credit considerations.
|
(b)
|
Balance excludes
$2 million
of receivables, payables, and accrued income, net.
|
|
|
Net derivative commodity contracts
|
|||||||
Three Months
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Ameren
|
|||
Fuel oils:
|
|
|
|
|
|
|
|||
Beginning balance at July 1, 2013
|
$
|
3
|
|
$
|
(a)
|
|
$
|
3
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
1
|
|
|
(a)
|
|
|
1
|
|
Total realized and unrealized gains (losses)
|
|
1
|
|
|
(a)
|
|
|
1
|
|
Purchases
|
|
1
|
|
|
(a)
|
|
|
1
|
|
Sales
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Settlements
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Ending balance at September 30, 2013
|
$
|
3
|
|
$
|
(a)
|
|
$
|
3
|
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
|
$
|
1
|
|
$
|
(a)
|
|
$
|
1
|
|
Natural gas:
|
|
|
|
|
|
|
|||
Beginning balance at July 1, 2013
|
$
|
(1
|
)
|
$
|
2
|
|
$
|
1
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
Total realized and unrealized gains (losses)
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
Purchases
|
|
1
|
|
|
—
|
|
|
1
|
|
Ending balance at September 30, 2013
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
|
$
|
—
|
|
$
|
(1
|
)
|
$
|
(1
|
)
|
Power:
|
|
|
|
|
|
|
|||
Beginning balance at July 1, 2013
|
$
|
37
|
|
$
|
(80
|
)
|
$
|
(43
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
(3
|
)
|
|
(17
|
)
|
|
(20
|
)
|
Total realized and unrealized gains (losses)
|
|
(3
|
)
|
|
(17
|
)
|
|
(20
|
)
|
Sales
|
|
1
|
|
|
—
|
|
|
1
|
|
Settlements
|
|
(6
|
)
|
|
3
|
|
|
(3
|
)
|
Transfers into Level 3
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
Ending balance at September 30, 2013
|
$
|
28
|
|
$
|
(94
|
)
|
$
|
(66
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
|
$
|
(2
|
)
|
$
|
(16
|
)
|
$
|
(18
|
)
|
Uranium:
|
|
|
|
|
|
|
|||
Beginning balance at July 1, 2013
|
$
|
(3
|
)
|
$
|
(a)
|
|
$
|
(3
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
—
|
|
|
(a)
|
|
|
—
|
|
Total realized and unrealized gains (losses)
|
|
—
|
|
|
(a)
|
|
|
—
|
|
Purchases
|
|
(2
|
)
|
|
(a)
|
|
|
(2
|
)
|
Ending balance at September 30, 2013
|
$
|
(5
|
)
|
$
|
(a)
|
|
$
|
(5
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
|
$
|
(2
|
)
|
$
|
(a)
|
|
$
|
(2
|
)
|
(a)
|
Not applicable.
|
|
|
Net derivative commodity contracts
|
|||||||
Three Months
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Ameren
|
|||
Fuel oils:
|
|
|
|
|
|
|
|||
Beginning balance at July 1, 2012
|
$
|
3
|
|
$
|
(a)
|
|
$
|
3
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
1
|
|
|
(a)
|
|
|
1
|
|
Total realized and unrealized gains (losses)
|
|
1
|
|
|
(a)
|
|
|
1
|
|
Purchases
|
|
2
|
|
|
(a)
|
|
|
2
|
|
Sales
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Ending balance at September 30, 2012
|
$
|
5
|
|
$
|
(a)
|
|
$
|
5
|
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012
|
$
|
2
|
|
$
|
(a)
|
|
$
|
2
|
|
Power
(b)
:
|
|
|
|
|
|
|
|||
Beginning balance at July 1, 2012
|
$
|
26
|
|
$
|
(221
|
)
|
$
|
(81
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
(4
|
)
|
|
2
|
|
|
(6
|
)
|
Total realized and unrealized gains (losses)
|
|
(4
|
)
|
|
2
|
|
|
(6
|
)
|
Sales
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
Settlements
|
|
(4
|
)
|
|
54
|
|
|
(1
|
)
|
Transfers out of Level 3
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
Ending balance at September 30, 2012
|
$
|
15
|
|
$
|
(165
|
)
|
$
|
(91
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012
|
$
|
(5
|
)
|
$
|
(2
|
)
|
$
|
(7
|
)
|
Uranium:
|
|
|
|
|
|
|
|||
Beginning balance at July 1, 2012
|
$
|
(1
|
)
|
|
(a)
|
|
$
|
(1
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Total realized and unrealized gains (losses)
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Ending balance at September 30, 2012
|
$
|
(2
|
)
|
|
(a)
|
|
$
|
(2
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012
|
$
|
(1
|
)
|
|
(a)
|
|
$
|
(1
|
)
|
(a)
|
Not applicable.
|
(b)
|
Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.
|
|
|
Net derivative commodity contracts
|
|||||||
Nine Months
|
|
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
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Total realized and unrealized gains (losses)
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Purchases
|
|
2
|
|
|
(a)
|
|
|
2
|
|
Sales
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Settlements
|
|
(2
|
)
|
|
(a)
|
|
|
(2
|
)
|
Ending balance at September 30, 2013
|
$
|
3
|
|
$
|
(a)
|
|
$
|
3
|
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 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 September 30, 2013
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Power:
|
|
|
|
|
|
|
|||
Beginning balance at January 1, 2013
|
$
|
11
|
|
$
|
(111
|
)
|
$
|
(100
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
3
|
|
|
(2
|
)
|
|
1
|
|
Total realized and unrealized gains (losses)
|
|
3
|
|
|
(2
|
)
|
|
1
|
|
Purchases
|
|
40
|
|
|
—
|
|
|
40
|
|
Sales
|
|
1
|
|
|
—
|
|
|
1
|
|
Settlements
|
|
(28
|
)
|
|
19
|
|
|
(9
|
)
|
Transfers into Level 3
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
Transfers out of Level 3
|
|
4
|
|
|
—
|
|
|
4
|
|
Ending balance at September 30, 2013
|
$
|
28
|
|
$
|
(94
|
)
|
$
|
(66
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
|
$
|
—
|
|
$
|
(7
|
)
|
$
|
(7
|
)
|
Uranium:
|
|
|
|
|
|
|
|||
Beginning balance at January 1, 2013
|
$
|
(2
|
)
|
$
|
(a)
|
|
$
|
(2
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
(2
|
)
|
|
(a)
|
|
|
(2
|
)
|
Total realized and unrealized gains (losses)
|
|
(2
|
)
|
|
(a)
|
|
|
(2
|
)
|
Purchases
|
|
(2
|
)
|
|
(a)
|
|
|
(2
|
)
|
Settlements
|
|
1
|
|
|
(a)
|
|
|
1
|
|
Ending balance at September 30, 2013
|
$
|
(5
|
)
|
$
|
(a)
|
|
$
|
(5
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
|
$
|
(2
|
)
|
$
|
(a)
|
|
$
|
(2
|
)
|
(a)
|
Not applicable.
|
|
|
Net derivative commodity contracts
|
|||||||
Nine Months
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Ameren
|
|||
Fuel oils:
|
|
|
|
|
|
|
|||
Beginning balance at January 1, 2012
|
$
|
3
|
|
$
|
(a)
|
|
$
|
3
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Total realized and unrealized gains (losses)
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Purchases
|
|
4
|
|
|
(a)
|
|
|
4
|
|
Sales
|
|
(2
|
)
|
|
(a)
|
|
|
(2
|
)
|
Settlements
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Transfers into Level 3
|
|
2
|
|
|
(a)
|
|
|
2
|
|
Ending balance at September 30, 2012
|
$
|
5
|
|
$
|
(a)
|
|
$
|
5
|
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012
|
$
|
(1
|
)
|
$
|
(a)
|
|
$
|
(1
|
)
|
Natural gas:
|
|
|
|
|
|
|
|||
Beginning balance at January 1, 2012
|
$
|
(14
|
)
|
$
|
(160
|
)
|
$
|
(174
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
(2
|
)
|
|
(26
|
)
|
|
(28
|
)
|
Total realized and unrealized gains (losses)
|
|
(2
|
)
|
|
(26
|
)
|
|
(28
|
)
|
Settlements
|
|
1
|
|
|
16
|
|
|
17
|
|
Transfers out of Level 3
|
|
15
|
|
|
170
|
|
|
185
|
|
Ending balance at September 30, 2012
|
$
|
—
|
|
$
|
—
|
|
$
|
—
|
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012
|
$
|
7
|
|
$
|
—
|
|
$
|
7
|
|
Power
(b)
:
|
|
|
|
|
|
|
|||
Beginning balance at January 1, 2012
|
$
|
21
|
|
$
|
(140
|
)
|
$
|
81
|
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
5
|
|
|
(219
|
)
|
|
(174
|
)
|
Total realized and unrealized gains (losses)
|
|
5
|
|
|
(219
|
)
|
|
(174
|
)
|
Purchases
|
|
22
|
|
|
—
|
|
|
22
|
|
Sales
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
Settlements
|
|
(28
|
)
|
|
194
|
|
|
(15
|
)
|
Transfers out of Level 3
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
Ending balance at September 30, 2012
|
$
|
15
|
|
$
|
(165
|
)
|
$
|
(91
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012
|
$
|
(1
|
)
|
$
|
(187
|
)
|
(c) $
|
(171
|
)
|
Uranium:
|
|
|
|
|
|
|
|||
Beginning balance at January 1, 2012
|
$
|
(1
|
)
|
$
|
(a)
|
|
$
|
(1
|
)
|
Realized and unrealized gains (losses):
|
|
|
|
|
|
|
|||
Included in regulatory assets/liabilities
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Total realized and unrealized gains (losses)
|
|
(1
|
)
|
|
(a)
|
|
|
(1
|
)
|
Ending balance at September 30, 2012
|
$
|
(2
|
)
|
$
|
(a)
|
|
$
|
(2
|
)
|
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2012
|
$
|
(1
|
)
|
$
|
(a)
|
|
$
|
(1
|
)
|
(a)
|
Not applicable.
|
(b)
|
Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.
|
(c)
|
The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois’ swap contracts, which expire May 2032.
|
|
Three Months
|
|
Nine Months
|
||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Ameren - derivative commodity contracts:
|
|
|
|
|
|
|
|
||||||||
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
|
—
|
|
|
—
|
|
|
—
|
|
|
185
|
|
||||
Transfers into Level 3 / Transfers out of Level 2 - Power
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
||||
Transfers out of Level 3 / Transfers into Level 2 - Power
|
—
|
|
|
(2
|
)
|
|
4
|
|
|
(4
|
)
|
||||
Net fair value of Level 3 transfers
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
|
$
|
1
|
|
|
$
|
183
|
|
Ameren Missouri - derivative commodity contracts:
|
|
|
|
|
|
|
|
||||||||
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
||||
Transfers into Level 3 / Transfers out of Level 2 - Power
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
||||
Transfers out of Level 3 / Transfers into Level 2 - Power
|
—
|
|
|
(2
|
)
|
|
4
|
|
|
(4
|
)
|
||||
Net fair value of Level 3 transfers
|
$
|
(1
|
)
|
|
$
|
(2
|
)
|
|
$
|
1
|
|
|
$
|
13
|
|
Ameren Illinois - derivative commodity contracts:
|
|
|
|
|
|
|
|
||||||||
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
170
|
|
|
September 30, 2013
|
|
December 31, 2012
|
||||||||||||
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Ameren:
(a)(b)
|
|
|
|
|
|
|
|
||||||||
Long-term debt and capital lease obligations (including current portion)
|
$
|
6,158
|
|
|
$
|
6,596
|
|
|
$
|
6,157
|
|
|
$
|
7,110
|
|
Preferred stock
|
142
|
|
|
123
|
|
|
142
|
|
|
123
|
|
||||
Ameren Missouri:
|
|
|
|
|
|
|
|
||||||||
Long-term debt and capital lease obligations (including current portion)
|
$
|
4,006
|
|
|
$
|
4,227
|
|
|
$
|
4,006
|
|
|
$
|
4,625
|
|
Preferred stock
|
80
|
|
|
74
|
|
|
80
|
|
|
74
|
|
||||
Ameren Illinois:
|
|
|
|
|
|
|
|
||||||||
Long-term debt (including current portion)
|
$
|
1,727
|
|
|
$
|
1,922
|
|
|
$
|
1,727
|
|
|
$
|
2,020
|
|
Preferred stock
|
62
|
|
|
49
|
|
|
62
|
|
|
49
|
|
(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 balance sheet.
|
•
|
$154 million
related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. As of
September 30, 2013
, this amount does not represent an incremental consolidated Ameren obligation; rather, it represents Ameren parental guarantees of subsidiary obligations to third parties, which may include affiliates, 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
September 30, 2013
, which represents the total amount Ameren (parent) could be required to fund based on
September 30, 2013
market prices.
|
•
|
$25 million
provided to a clearing broker acting as futures commission merchant for the clearing of certain power, natural gas, and fuels commodity transactions for AER.
|
•
|
$13 million
related to requirements for asset transactions, leasing, Medina Valley transactions through MISO and other agreements. At
September 30, 2013
, Ameren estimated it had no exposure to any of these guarantees.
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|||||||
Agreement
|
Income Statement
Line Item
|
|
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|||
Ameren Missouri power supply
|
Operating Revenues
|
|
2013
|
$
|
(b)
|
|
$
|
(a)
|
$
|
1
|
$
|
(a)
|
|
|
agreements with Ameren Illinois
|
|
|
2012
|
|
(b)
|
|
|
(a)
|
|
|
(b)
|
|
(a)
|
|
Ameren Missouri and Ameren Illinois
|
Operating Revenues
|
|
2013
|
|
4
|
|
|
(b)
|
|
|
15
|
|
1
|
|
rent and facility services
|
|
|
2012
|
|
5
|
|
|
(b)
|
|
|
14
|
|
1
|
|
Ameren Missouri and Genco gas
|
Operating Revenues
|
|
2013
|
|
(b)
|
|
|
(a)
|
|
|
1
|
|
(a)
|
|
transportation agreement
|
|
|
2012
|
|
(b)
|
|
|
(a)
|
|
|
1
|
|
(a)
|
|
Transmission services agreement
|
Operating Revenues
|
|
2013
|
|
(a)
|
|
|
11
|
|
|
(a)
|
|
24
|
|
with Marketing Company
|
|
|
2012
|
|
(a)
|
|
|
5
|
|
|
(a)
|
|
11
|
|
Total Operating Revenues
|
|
|
2013
|
$
|
4
|
|
$
|
11
|
|
$
|
17
|
$
|
25
|
|
|
|
|
2012
|
|
5
|
|
|
5
|
|
|
15
|
|
12
|
|
Ameren Illinois power supply
|
Purchased Power
|
|
2013
|
$
|
(a)
|
|
$
|
46
|
|
$
|
(a)
|
$
|
94
|
|
agreements with Marketing Company
|
|
|
2012
|
|
(a)
|
|
|
83
|
|
|
(a)
|
|
243
|
|
Ameren Illinois power supply
|
Purchased Power
|
|
2013
|
|
(a)
|
|
|
(b)
|
|
|
(a)
|
|
1
|
|
agreements with Ameren Missouri
|
|
|
2012
|
|
(a)
|
|
|
(b)
|
|
|
(a)
|
|
(b)
|
|
Total Purchased Power
|
|
|
2013
|
$
|
(a)
|
|
$
|
46
|
|
$
|
(a)
|
$
|
95
|
|
|
|
|
2012
|
|
(a)
|
|
|
83
|
|
|
(a)
|
|
243
|
|
Ameren Services support services
|
Other Operations and Maintenance
|
|
2013
|
$
|
25
|
|
$
|
22
|
|
$
|
85
|
$
|
70
|
|
agreement
|
|
|
2012
|
|
26
|
|
|
22
|
|
|
81
|
|
67
|
|
Insurance premiums
(c)
|
Other Operations and Maintenance
|
|
2013
|
|
(b)
|
|
|
(a)
|
|
|
(b)
|
|
(a)
|
|
|
|
|
2012
|
|
(b)
|
|
|
(a)
|
|
|
(b)
|
|
(a)
|
|
Total Other Operations and
|
|
|
2013
|
$
|
25
|
|
$
|
22
|
|
$
|
85
|
$
|
70
|
|
Maintenance Expenses
|
|
|
2012
|
|
26
|
|
|
22
|
|
|
81
|
|
67
|
|
Money pool borrowings (advances)
|
Interest Charges
|
|
2013
|
$
|
(b)
|
|
$
|
(b)
|
|
$
|
$1
|
$
|
(b)
|
|
|
|
|
2012
|
|
(b)
|
|
|
(b)
|
|
|
(b)
|
|
(b)
|
|
(a)
|
Not applicable.
|
(b)
|
Amount less than $1 million.
|
(c)
|
Represents insurance premiums paid to Missouri Energy Risk Assurance Company, an affiliate, for replacement power.
|
Type and Source of Coverage
|
Maximum Coverages
|
|
Maximum Assessments
for Single Incidents
|
|
||||
Public liability and nuclear worker liability:
|
|
|
|
|
||||
American Nuclear Insurers
|
$
|
375
|
|
|
$
|
—
|
|
|
Pool participation
|
13,312
|
|
(a)
|
128
|
|
(b)
|
||
|
$
|
13,687
|
|
(c)
|
$
|
128
|
|
|
Property damage:
|
|
|
|
|
||||
Nuclear Electric Insurance Ltd.
|
$
|
2,250
|
|
(d)
|
$
|
23
|
|
(e)
|
European Mutual Association for Nuclear Insurance
|
500
|
|
(f)
|
—
|
|
|
||
|
$
|
2,750
|
|
|
$
|
23
|
|
|
Replacement power:
|
|
|
|
|
||||
Nuclear Electric Insurance Ltd.
|
$
|
490
|
|
(g)
|
$
|
9
|
|
(e)
|
Missouri Energy Risk Assurance Company
|
64
|
|
(h)
|
—
|
|
|
(a)
|
Provided through mandatory participation in an industry-wide retrospective premium assessment program.
|
(b)
|
Retrospective premium under Price-Anderson. 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 United States commercial reactor, payable at
$19 million
per year.
|
(c)
|
Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to
$128 million
per incident for each licensed reactor it operates with a maximum of
$19 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)
|
Nuclear Electric Insurance Ltd. provides
$2.25 billion
in property damage, decontamination, 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 and includes one free reinstatement.
|
(e)
|
All Nuclear Electric Insurance Ltd. insured plants could be subject to assessments should losses exceed the accumulated funds from Nuclear Electric Insurance Ltd.
|
(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 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
.
|
(h)
|
Provides 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. and is for a weekly indemnity up to
$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 9 - Related Party Transactions for more information on this affiliate transaction.
|
|
Coal
|
|
Natural
Gas
|
|
Nuclear
Fuel
|
|
Purchased
Power
(a)
|
|
Methane
Gas
|
|
Other
|
|
Total
|
||||||||||||||
Ameren:
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
2013
|
$
|
605
|
|
|
$
|
109
|
|
|
$
|
17
|
|
|
$
|
162
|
|
|
$
|
1
|
|
|
$
|
87
|
|
|
$
|
981
|
|
2014
|
617
|
|
|
292
|
|
|
68
|
|
|
302
|
|
|
3
|
|
|
158
|
|
|
1,440
|
|
|||||||
2015
|
640
|
|
|
155
|
|
|
63
|
|
|
154
|
|
|
4
|
|
|
114
|
|
|
1,130
|
|
|||||||
2016
|
665
|
|
|
85
|
|
|
81
|
|
|
67
|
|
|
4
|
|
|
64
|
|
|
966
|
|
|||||||
2017
|
683
|
|
|
47
|
|
|
58
|
|
|
44
|
|
|
5
|
|
|
56
|
|
|
893
|
|
|||||||
Thereafter
|
245
|
|
|
100
|
|
|
216
|
|
|
501
|
|
|
97
|
|
|
246
|
|
|
1,405
|
|
|||||||
Total
|
$
|
3,455
|
|
|
$
|
788
|
|
|
$
|
503
|
|
|
$
|
1,230
|
|
|
$
|
114
|
|
|
$
|
725
|
|
|
$
|
6,815
|
|
Ameren Missouri:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
2013
|
$
|
605
|
|
|
$
|
27
|
|
|
$
|
17
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
66
|
|
|
$
|
719
|
|
2014
|
617
|
|
|
50
|
|
|
68
|
|
|
19
|
|
|
3
|
|
|
127
|
|
|
884
|
|
|||||||
2015
|
640
|
|
|
30
|
|
|
63
|
|
|
19
|
|
|
4
|
|
|
85
|
|
|
841
|
|
|||||||
2016
|
665
|
|
|
16
|
|
|
81
|
|
|
19
|
|
|
4
|
|
|
40
|
|
|
825
|
|
|||||||
2017
|
683
|
|
|
11
|
|
|
58
|
|
|
19
|
|
|
5
|
|
|
32
|
|
|
808
|
|
|||||||
Thereafter
|
245
|
|
|
28
|
|
|
216
|
|
|
129
|
|
|
97
|
|
|
144
|
|
|
859
|
|
|||||||
Total
|
$
|
3,455
|
|
|
$
|
162
|
|
|
$
|
503
|
|
|
$
|
208
|
|
|
$
|
114
|
|
|
$
|
494
|
|
|
$
|
4,936
|
|
Ameren Illinois:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
2013
|
$
|
—
|
|
|
$
|
82
|
|
|
$
|
—
|
|
|
$
|
159
|
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
250
|
|
2014
|
—
|
|
|
242
|
|
|
—
|
|
|
283
|
|
|
—
|
|
|
22
|
|
|
547
|
|
|||||||
2015
|
—
|
|
|
125
|
|
|
—
|
|
|
135
|
|
|
—
|
|
|
24
|
|
|
284
|
|
|||||||
2016
|
—
|
|
|
69
|
|
|
—
|
|
|
48
|
|
|
—
|
|
|
24
|
|
|
141
|
|
|||||||
2017
|
—
|
|
|
36
|
|
|
—
|
|
|
25
|
|
|
—
|
|
|
24
|
|
|
85
|
|
|||||||
Thereafter
|
—
|
|
|
72
|
|
|
—
|
|
|
372
|
|
|
—
|
|
|
102
|
|
|
546
|
|
|||||||
Total
|
$
|
—
|
|
|
$
|
626
|
|
|
$
|
—
|
|
|
$
|
1,022
|
|
|
$
|
—
|
|
|
$
|
205
|
|
|
$
|
1,853
|
|
(a)
|
The purchased power amounts for Ameren and Ameren Illinois includes
twenty
-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)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
•
|
Ameren’s divestiture of its Merchant Generation business;
|
•
|
additional or modified federal or state requirements;
|
•
|
further regulation of greenhouse gas emissions;
|
•
|
revisions to CAIR or reinstatement of CSAPR;
|
•
|
delays or accelerations of rulemaking and implementation by the EPA or state agencies;
|
•
|
new national ambient air quality standards, new standards intended to achieve national ambient air quality standards, or changes to existing standards for ozone, fine particulates, SO
2
, and NO
x
emissions;
|
•
|
additional or new rules governing air pollutant transport;
|
•
|
regulations or requirements under the Clean Water Act regarding cooling water intake structures or effluent standards;
|
•
|
finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR;
|
•
|
new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;
|
•
|
new technology;
|
•
|
changes in expected power prices;
|
•
|
variations 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
|
|
(a)
|
Ameren Missouri’s expenditures are expected to be recoverable from ratepayers.
|
|
2013
|
|
2014 - 2017
|
|
2018 - 2022
|
|
Total
|
||||||||||||||||||||
Genco
(a)
|
$
|
30
|
|
|
$
|
100
|
|
-
|
$
|
125
|
|
|
$
|
220
|
|
-
|
$
|
270
|
|
|
$
|
350
|
|
-
|
$
|
425
|
|
AERG
|
5
|
|
|
20
|
|
-
|
25
|
|
|
20
|
|
-
|
25
|
|
|
45
|
|
-
|
55
|
|
|||||||
Total
(b)
|
$
|
35
|
|
|
$
|
120
|
|
-
|
$
|
150
|
|
|
$
|
240
|
|
-
|
$
|
295
|
|
|
$
|
395
|
|
-
|
$
|
480
|
|
(a)
|
Includes estimated costs of approximately
$20 million
annually, excluding capitalized interest, from 2013 through 2017 for construction of two scrubbers at the Newton energy center.
|
(b)
|
Assumes the Merchant Generation facilities are owned by Ameren.
|
•
|
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, or Ameren’s ability after the divestiture of New AER occurs, 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.
|
|
Estimate
|
|
Recorded
Liability
(a)
|
||||||||
|
Low
|
|
High
|
|
|||||||
Ameren
|
$
|
251
|
|
|
$
|
337
|
|
|
$
|
251
|
|
Ameren Missouri
|
5
|
|
|
6
|
|
|
5
|
|
|||
Ameren Illinois
|
246
|
|
|
331
|
|
|
246
|
|
(a)
|
Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was a better estimate.
|
Ameren
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Total
(a)
|
1
|
|
55
|
|
63
|
|
85
|
(a)
|
Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
|
|
Pension Benefits
(a)
|
|
Postretirement Benefits
(a)
|
||||||||||||||||||||||||||||
|
Three Months
|
|
Nine Months
|
|
Three Months
|
|
Nine Months
|
||||||||||||||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||||||||||
Service cost
|
$
|
23
|
|
|
$
|
20
|
|
|
$
|
69
|
|
|
$
|
61
|
|
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
17
|
|
|
$
|
16
|
|
Interest cost
|
40
|
|
|
42
|
|
|
121
|
|
|
125
|
|
|
11
|
|
|
12
|
|
|
34
|
|
|
36
|
|
||||||||
Expected return on plan assets
|
(54
|
)
|
|
(52
|
)
|
|
(162
|
)
|
|
(156
|
)
|
|
(16
|
)
|
|
(14
|
)
|
|
(47
|
)
|
|
(42
|
)
|
||||||||
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Transition obligation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||||||
Prior service cost (benefit)
|
(1
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|
(3
|
)
|
|
(3
|
)
|
||||||||
Actuarial loss
|
23
|
|
|
19
|
|
|
69
|
|
|
56
|
|
|
2
|
|
|
1
|
|
|
6
|
|
|
3
|
|
||||||||
Net periodic benefit cost
|
$
|
31
|
|
|
$
|
28
|
|
|
$
|
94
|
|
|
$
|
83
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
7
|
|
|
$
|
11
|
|
(a)
|
Excludes the EEI plans as they are included in discontinued operations.
|
|
Pension Costs
|
|
Postretirement Costs
|
||||||||||||||||||||||||||||
|
Three Months
|
|
Nine Months
|
|
Three Months
|
|
Nine Months
|
||||||||||||||||||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||||||||||
Ameren Missouri
|
$
|
18
|
|
|
$
|
16
|
|
|
$
|
54
|
|
|
$
|
48
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
7
|
|
|
$
|
7
|
|
Ameren Illinois
|
10
|
|
|
9
|
|
|
31
|
|
|
27
|
|
|
(b)
|
|
|
1
|
|
|
(b)
|
|
|
3
|
|
||||||||
Other
|
3
|
|
|
3
|
|
|
9
|
|
|
8
|
|
|
(b)
|
|
|
1
|
|
|
(b)
|
|
|
1
|
|
||||||||
Ameren
(a)
|
$
|
31
|
|
|
$
|
28
|
|
|
$
|
94
|
|
|
$
|
83
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
7
|
|
|
$
|
11
|
|
(a)
|
Includes amounts for Ameren registrants and nonregistrant subsidiaries, but excludes the EEI plans as they are included in discontinued operations.
|
(b)
|
Less than $1 million.
|
Three Months
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Other
|
|
Intersegment
Eliminations
|
|
Consolidated
|
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
|
||||||||||
External revenues
|
$
|
1,088
|
|
|
$
|
547
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
1,638
|
|
|
Intersegment revenues
|
5
|
|
|
—
|
|
|
1
|
|
|
(6
|
)
|
|
—
|
|
|
|||||
Net income (loss) attributable to Ameren Corporation from continuing operations
|
238
|
|
|
77
|
|
|
(10
|
)
|
|
—
|
|
|
305
|
|
|
|||||
2012
|
|
|
|
|
|
|
|
|
|
|
||||||||||
External revenues
|
$
|
1,059
|
|
|
$
|
647
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
1,709
|
|
|
Intersegment revenues
|
5
|
|
|
1
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
|||||
Net income (loss) attributable to Ameren Corporation from continuing operations
|
236
|
|
|
71
|
|
|
2
|
|
|
—
|
|
|
309
|
|
|
|||||
Nine Months
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
|
||||||||||
External revenues
|
$
|
2,760
|
|
|
$
|
1,744
|
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
4,516
|
|
|
Intersegment revenues
|
18
|
|
|
3
|
|
|
2
|
|
|
(23
|
)
|
|
—
|
|
|
|||||
Net income (loss) attributable to Ameren Corporation from continuing operations
|
362
|
|
|
139
|
|
|
(37
|
)
|
|
—
|
|
|
464
|
|
|
|||||
2012
|
|
|
|
|
|
|
|
|
|
|
||||||||||
External revenues
|
$
|
2,583
|
|
|
$
|
1,935
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
4,523
|
|
|
Intersegment revenues
|
16
|
|
|
1
|
|
|
2
|
|
|
(19
|
)
|
|
—
|
|
|
|||||
Net income (loss) attributable to Ameren Corporation from continuing operations
|
400
|
|
|
130
|
|
|
(23
|
)
|
|
—
|
|
|
507
|
|
|
|||||
As of September 30, 2013:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
13,231
|
|
|
$
|
7,439
|
|
|
$
|
1,375
|
|
|
$
|
(1,055
|
)
|
|
$
|
20,990
|
|
(a)
|
As of December 31, 2012:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets
|
$
|
13,043
|
|
|
$
|
7,282
|
|
|
$
|
1,228
|
|
|
$
|
(934
|
)
|
|
$
|
20,619
|
|
(a)
|
•
|
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.
|
•
|
AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company, and, through Genco, an
80%
ownership interest in EEI, which Ameren consolidates for financial reporting purposes.
|
•
|
decreased electric demand resulting from summer temperatures that were cooler than last year’s warmer-than-normal temperatures, partially offset in both periods by the absence of the collar adjustment impact on Ameren Illinois earnings which came into effect with the hot summer weather in 2012, and partially offset in the nine-month period by increased natural gas demand in the first quarter of 2013 (estimated at 15 cents per share and 10 cents per share, respectively); and
|
•
|
a reduction in revenues at Ameren Missouri resulting from the Missouri Court of Appeals’ May 2013 decision, which upheld the MoPSC's April 2011 order, and a MoPSC order issued in July 2013 for the estimated obligation to refund to customers amounts associated with certain long-term partial requirements sales recognized for the period from October 1, 2009, to May 31, 2011 (1 cent per share and 7 cents per share, respectively).
|
•
|
costs associated with the Callaway energy center's scheduled refueling and maintenance outage in the second quarter of 2013. There was no Callaway refueling and maintenance outage in 2012 (10 cents per share); and
|
•
|
the absence in 2013 of a 2012 Entergy refund not included in the FAC that reduced Ameren Missouri's purchased power expense and increased interest income. In June 2012, FERC ordered the refund from Entergy for a power purchase agreement that expired in 2009 (7 cents per share).
|
•
|
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 directed by the rate order. This excludes
|
•
|
an increase in Ameren Illinois' electric delivery earnings under formula ratemaking. The third quarter was favorably impacted by timing differences, increased rate base and a higher allowed return on equity. The nine-month period was favorably impacted by increased rate base, a higher allowed return on equity, and lower required contributions pursuant to the IEIMA. (8 cents per share and 2 cents per share, respectively);
|
•
|
higher revenues associated with Ameren Missouri's MEEIA energy efficiency lost revenue recovery mechanism (3 cents per share and 5 cents per share, respectively), which are partially offset by lower revenues resulting from reduced demand due to energy efficiency programs; and
|
•
|
higher electric transmission rates at Ameren Illinois and ATXI (1 cent per share and 6 cents per share, respectively).
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Other /
Intersegment
Eliminations
|
|
Total
|
||||||||
Three Months 2013:
|
|
|
|
|
|
|
|
||||||||
Electric margin
|
$
|
820
|
|
|
$
|
336
|
|
|
$
|
1
|
|
|
$
|
1,157
|
|
Natural gas margin
|
13
|
|
|
77
|
|
|
(1
|
)
|
|
89
|
|
||||
Other revenues
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
||||
Other operations and maintenance
|
(212
|
)
|
|
(166
|
)
|
|
(5
|
)
|
|
(383
|
)
|
||||
Depreciation and amortization
|
(114
|
)
|
|
(59
|
)
|
|
(2
|
)
|
|
(175
|
)
|
||||
Taxes other than income taxes
|
(91
|
)
|
|
(30
|
)
|
|
—
|
|
|
(121
|
)
|
||||
Other income and (expenses)
|
14
|
|
|
1
|
|
|
—
|
|
|
15
|
|
||||
Interest charges
|
(43
|
)
|
|
(31
|
)
|
|
(14
|
)
|
|
(88
|
)
|
||||
Income (taxes) benefit
|
(149
|
)
|
|
(51
|
)
|
|
13
|
|
|
(187
|
)
|
||||
Income (loss) from continuing operations
|
239
|
|
|
77
|
|
|
(9
|
)
|
|
307
|
|
||||
Loss from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
(3
|
)
|
||||
Net income (loss)
|
239
|
|
|
77
|
|
|
(12
|
)
|
|
304
|
|
||||
Noncontrolling interest and preferred dividends
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
||||
Net income (loss) attributable to Ameren Corporation
|
$
|
238
|
|
|
$
|
77
|
|
|
$
|
(13
|
)
|
|
$
|
302
|
|
Three Months 2012:
|
|
|
|
|
|
|
|
||||||||
Electric margin
|
$
|
817
|
|
|
$
|
312
|
|
|
$
|
(4
|
)
|
|
$
|
1,125
|
|
Natural gas margin
|
13
|
|
|
77
|
|
|
—
|
|
|
90
|
|
||||
Other revenues
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Other operations and maintenance
|
(203
|
)
|
|
(159
|
)
|
|
—
|
|
|
(362
|
)
|
||||
Depreciation and amortization
|
(111
|
)
|
|
(55
|
)
|
|
5
|
|
|
(161
|
)
|
||||
Taxes other than income taxes
|
(87
|
)
|
|
(24
|
)
|
|
(3
|
)
|
|
(114
|
)
|
||||
Other income and (expenses)
|
11
|
|
|
—
|
|
|
—
|
|
|
11
|
|
||||
Interest charges
|
(55
|
)
|
|
(34
|
)
|
|
(10
|
)
|
|
(99
|
)
|
||||
Income (taxes) benefit
|
(148
|
)
|
|
(46
|
)
|
|
15
|
|
|
(179
|
)
|
||||
Income (loss) from continuing operations
|
237
|
|
|
71
|
|
|
3
|
|
|
311
|
|
||||
Income from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
63
|
|
|
63
|
|
||||
Net income
|
237
|
|
|
71
|
|
|
66
|
|
|
374
|
|
||||
Noncontrolling interest and preferred dividends
|
(1
|
)
|
|
—
|
|
|
1
|
|
|
—
|
|
||||
Net income attributable to Ameren Corporation
|
$
|
236
|
|
|
$
|
71
|
|
|
$
|
67
|
|
|
$
|
374
|
|
Nine Months 2013:
|
|
|
|
|
|
|
|
||||||||
Electric margin
|
$
|
1,919
|
|
|
$
|
857
|
|
|
$
|
(1
|
)
|
|
$
|
2,775
|
|
Natural gas margin
|
58
|
|
|
293
|
|
|
(2
|
)
|
|
349
|
|
||||
Other revenues
|
1
|
|
|
2
|
|
|
(3
|
)
|
|
—
|
|
||||
Other operations and maintenance
|
(686
|
)
|
|
(538
|
)
|
|
(5
|
)
|
|
(1,229
|
)
|
||||
Depreciation and amortization
|
(338
|
)
|
|
(182
|
)
|
|
(8
|
)
|
|
(528
|
)
|
||||
Taxes other than income taxes
|
(247
|
)
|
|
(102
|
)
|
|
(5
|
)
|
|
(354
|
)
|
||||
Other income and (expenses)
|
34
|
|
|
—
|
|
|
(1
|
)
|
|
33
|
|
||||
Interest charges
|
(159
|
)
|
|
(96
|
)
|
|
(34
|
)
|
|
(289
|
)
|
||||
Income (taxes) benefit
|
(217
|
)
|
|
(93
|
)
|
|
22
|
|
|
(288
|
)
|
||||
Income (loss) from continuing operations
|
365
|
|
|
141
|
|
|
(37
|
)
|
|
469
|
|
||||
Loss from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
(212
|
)
|
|
(212
|
)
|
||||
Net income (loss)
|
365
|
|
|
141
|
|
|
(249
|
)
|
|
257
|
|
||||
Noncontrolling interest and preferred dividends
|
(3
|
)
|
|
(2
|
)
|
|
—
|
|
|
(5
|
)
|
||||
Net income (loss) attributable to Ameren Corporation
|
$
|
362
|
|
|
$
|
139
|
|
|
$
|
(249
|
)
|
|
$
|
252
|
|
Nine Months 2012:
|
|
|
|
|
|
|
|
||||||||
Electric margin
|
$
|
1,898
|
|
|
$
|
828
|
|
|
$
|
(8
|
)
|
|
$
|
2,718
|
|
Natural gas margin
|
52
|
|
|
270
|
|
|
(1
|
)
|
|
321
|
|
||||
Other revenues
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
||||
Other operations and maintenance
|
(611
|
)
|
|
(513
|
)
|
|
(2
|
)
|
|
(1,126
|
)
|
||||
Depreciation and amortization
|
(328
|
)
|
|
(165
|
)
|
|
(3
|
)
|
|
(496
|
)
|
||||
Taxes other than income taxes
|
(236
|
)
|
|
(94
|
)
|
|
(7
|
)
|
|
(337
|
)
|
||||
Other income and (expenses)
|
37
|
|
|
(10
|
)
|
|
(2
|
)
|
|
25
|
|
||||
Interest charges
|
(167
|
)
|
|
(98
|
)
|
|
(30
|
)
|
|
(295
|
)
|
||||
Income (taxes) benefit
|
(243
|
)
|
|
(86
|
)
|
|
31
|
|
|
(298
|
)
|
||||
Income (loss) from continuing operations
|
403
|
|
|
132
|
|
|
(23
|
)
|
|
512
|
|
||||
Loss from discontinued operations, net of tax
|
—
|
|
|
—
|
|
|
(331
|
)
|
|
(331
|
)
|
||||
Net income (loss)
|
403
|
|
|
132
|
|
|
(354
|
)
|
|
181
|
|
||||
Noncontrolling interest and preferred dividends
|
(3
|
)
|
|
(2
|
)
|
|
6
|
|
|
1
|
|
||||
Net income (loss) attributable to Ameren Corporation
|
$
|
400
|
|
|
$
|
130
|
|
|
$
|
(348
|
)
|
|
$
|
182
|
|
Three Months
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Other
(a)
|
|
Ameren
|
||||||||
Electric revenue change:
|
|
|
|
|
|
|
|
||||||||
Effect of weather (estimate)
(b)
|
$
|
(59
|
)
|
|
$
|
(16
|
)
|
|
$
|
—
|
|
|
$
|
(75
|
)
|
Regulated rates:
|
|
|
|
|
|
|
|
||||||||
Base rates (estimate)
|
66
|
|
|
52
|
|
|
—
|
|
|
118
|
|
||||
Recovery of FAC under-recovery
(c)
|
22
|
|
|
—
|
|
|
—
|
|
|
22
|
|
||||
Off-system and transmission services revenues (reduction in base rates)
|
(7
|
)
|
|
—
|
|
|
1
|
|
|
(6
|
)
|
||||
FAC prudence review charge
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
||||
MEEIA (energy efficiency)
|
21
|
|
|
—
|
|
|
—
|
|
|
21
|
|
||||
Transmission services
|
(10
|
)
|
|
2
|
|
|
2
|
|
|
(6
|
)
|
||||
Gross receipts tax
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Bad debt, energy efficiency programs and environmental remediation cost riders
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
||||
Illinois pass-through power supply costs
|
—
|
|
|
(128
|
)
|
|
—
|
|
|
(128
|
)
|
||||
Sales volume (excluding the impact of abnormal weather)
|
(1
|
)
|
|
(8
|
)
|
|
—
|
|
|
(9
|
)
|
||||
Other
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|
(6
|
)
|
||||
Total electric revenue change
|
$
|
29
|
|
|
$
|
(104
|
)
|
|
$
|
3
|
|
|
$
|
(72
|
)
|
Fuel and purchased power change:
|
|
|
|
|
|
|
|
||||||||
Energy costs included in base rates
|
$
|
(4
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4
|
)
|
Recovery of FAC under-recovery
(c)
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
||||
Illinois pass-through power supply costs and other
|
—
|
|
|
128
|
|
|
2
|
|
|
130
|
|
||||
Total fuel and purchased power change
|
$
|
(26
|
)
|
|
$
|
128
|
|
|
$
|
2
|
|
|
$
|
104
|
|
Net change in electric margins
|
$
|
3
|
|
|
$
|
24
|
|
|
$
|
5
|
|
|
$
|
32
|
|
Natural gas margins change:
|
|
|
|
|
|
|
|
||||||||
Energy efficiency programs and environmental remediation cost riders
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Sales and other
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
||||
Net change in natural gas margins
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
(1
|
)
|
Nine Months
|
Ameren
Missouri
|
|
Ameren
Illinois
|
|
Other
(a)
|
|
Ameren
|
||||||||
Electric revenue change:
|
|
|
|
|
|
|
|
||||||||
Effect of weather (estimate)
(b)
|
$
|
(53
|
)
|
|
$
|
(15
|
)
|
|
$
|
—
|
|
|
$
|
(68
|
)
|
Regulated rates:
|
|
|
|
|
|
|
|
||||||||
Base rates (estimate)
|
149
|
|
|
48
|
|
|
—
|
|
|
197
|
|
||||
Recovery of FAC under-recovery
(c)
|
56
|
|
|
—
|
|
|
—
|
|
|
56
|
|
||||
Off-system and transmission services revenues (reduction in base rates)
|
9
|
|
|
—
|
|
|
—
|
|
|
9
|
|
||||
FAC prudence review charge
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
||||
MEEIA (energy efficiency)
|
43
|
|
|
—
|
|
|
—
|
|
|
43
|
|
||||
Transmission services
|
(24
|
)
|
|
18
|
|
|
8
|
|
|
2
|
|
||||
Gross receipts tax
|
9
|
|
|
—
|
|
|
—
|
|
|
9
|
|
||||
Bad debt, energy efficiency programs and environmental remediation cost riders
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
(7
|
)
|
||||
Illinois pass-through power supply costs
|
—
|
|
|
(273
|
)
|
|
—
|
|
|
(273
|
)
|
||||
Sales volume (excluding the impact of abnormal weather)
|
2
|
|
|
(11
|
)
|
|
—
|
|
|
(9
|
)
|
||||
Other
|
(3
|
)
|
|
(4
|
)
|
|
(2
|
)
|
|
(9
|
)
|
||||
Total electric revenue change
|
$
|
163
|
|
|
$
|
(244
|
)
|
|
$
|
6
|
|
|
$
|
(75
|
)
|
Fuel and purchased power change:
|
|
|
|
|
|
|
|
||||||||
Energy costs included in base rates
|
$
|
(62
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(62
|
)
|
Recovery of FAC under-recovery
(c)
|
(56
|
)
|
|
—
|
|
|
—
|
|
|
(56
|
)
|
FERC-ordered power purchase settlement in 2012
|
(24
|
)
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
||||
Illinois pass-through power supply costs and other
|
—
|
|
|
273
|
|
|
1
|
|
|
274
|
|
||||
Total fuel and purchased power change
|
$
|
(142
|
)
|
|
$
|
273
|
|
|
$
|
1
|
|
|
$
|
132
|
|
Net change in electric margins
|
$
|
21
|
|
|
$
|
29
|
|
|
$
|
7
|
|
|
$
|
57
|
|
Natural gas margins change:
|
|
|
|
|
|
|
|
||||||||
Effect of weather (estimate)
(b)
|
$
|
3
|
|
|
$
|
11
|
|
|
$
|
—
|
|
|
$
|
14
|
|
Base rates (estimate)
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
||||
Energy efficiency programs and environmental remediation cost riders
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
||||
Gross receipts tax
|
1
|
|
|
5
|
|
|
—
|
|
|
6
|
|
||||
Sales (excluding the impact of abnormal weather) and other
|
2
|
|
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
||||
Net change in natural gas margins
|
$
|
6
|
|
|
$
|
23
|
|
|
$
|
(1
|
)
|
|
$
|
28
|
|
(a)
|
Primarily includes amounts for ATXI and intercompany eliminations.
|
(b)
|
Represents the estimated margin impact resulting from the effects of changes in cooling and heating degree-days on electric and natural gas demand compared with the prior-year period 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 amortization of a previously recorded regulatory asset.
|
•
|
Higher Ameren Missouri electric base rates effective January 2013 (
$66 million
and
$149 million
, respectively), as a result of the 2012 MoPSC electric rate order, partially offset by an
increase
in net energy costs (
$11 million
and
$53 million
, respectively). The increase in net energy costs are the sum of the change in energy costs included in base rates (
$4 million
and
$62 million
, respectively) and the change in off-system and transmission services revenues (
-$7 million
and
$9 million
, respectively). Transmission services revenues for 2012 were not included in the FAC (
$10 million
and
$24 million
, respectively). See below for additional details regarding the FAC.
|
•
|
Electric delivery service formula ratemaking adjustments at Ameren Illinois resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA (
$52 million
and
$48 million
, respectively). The third quarter was favorably impacted by timing differences, increased rate base, a higher allowed return on equity, and absence of the collar adjustment impact on earnings which came into effect with the hot summer weather in 2012. The nine-month period was favorably impacted by increased rate base, a higher allowed return on equity, and absence of the collar adjustment.
|
•
|
Higher revenues associated with Ameren Missouri's MEEIA energy efficiency program cost recovery mechanism ($10 million and $23 million, respectively) and lost revenue recovery mechanism ($11 million and $20 million, respectively), effective January 2013, which
increased
revenues by a combined
$21 million
and
$43 million
, respectively. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs.
|
•
|
Excluding Ameren Missouri, higher transmission revenues at Ameren Illinois and ATXI, due to the forward-looking rate
|
•
|
Increased gross receipts taxes at Ameren Missouri, due primarily to the higher base rates (
$3 million
and
$9 million
, respectively). See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.
|
•
|
Summer weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as cooling degree-days decreased 20% and 24%, respectively, which
decreased
revenues by
$75 million
and
$68 million
, respectively. This excludes the impact of the collar adjustment discussed above.
|
•
|
A reduction in Ameren Missouri revenues resulting from the Missouri Court of Appeals’ May 2013 decision that upheld the MoPSC's April 2011 order and a MoPSC order issued in July 2013. Ameren Missouri recorded a FAC prudence review charge for its estimated obligation to refund to its electric customers the earnings associated with sales previously recognized by Ameren Missouri during the period from October 1, 2009, to May 31, 2011 (
$3 million
and
$25 million
, respectively). See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information regarding the FAC prudence review charge.
|
•
|
Absence in 2013 of a 2012 FERC-ordered Entergy refund that reduced Ameren Missouri’s purchased power expense that was not included in the FAC,
decreased
margins by
$24 million
for the
nine months ended September 30, 2013
, when compared with the same period in
2012
.
|
•
|
A decrease in recovery of bad debt, energy efficiency program costs and environmental remediation costs through
|
•
|
Excluding the estimated impact of abnormal weather, total sales volumes decreased 3% and 1%, respectively, due in part to decreased sales in the commercial and industrial sectors at Ameren Illinois (
$9 million
and
$9 million
, respectively).
|
•
|
Winter weather conditions in
2013
were normal compared to warmer-than-normal conditions in
2012
, as heating degree-days increased 42%, which increased revenues by
$14 million
for the
nine months ended September 30, 2013
, compared with the same period in
2012
.
|
•
|
An increase in recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms at Ameren Illinois (
$1 million
and
$6 million
, respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.
|
•
|
Increased gross receipts taxes, primarily at Ameren Illinois, due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by
$6 million
for the
nine months ended September 30, 2013
, compared with the same period in
2012
. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.
|
•
|
Increased Ameren Illinois natural gas rates effective in late January 2012,
increased
revenues by
$2 million
for the
nine months ended September 30, 2013
, when compared with the same period in
2012
.
|
•
|
Higher electric base rates, effective January 2013 (
$66 million
and
$149 million
, respectively), as a result of the 2012 MoPSC electric rate order, partially offset by an
increase
in net energy costs (
$11 million
and
$53 million
, respectively). The increase in net energy costs are the sum of the change in energy costs included in base rates (
$4 million
and
$62 million
, respectively) and the change in off-system and transmission services revenues (
-$7 million
and
$9 million
, respectively). Transmission services revenues for 2012 were not included in the FAC (
$10 million
and
$24 million
, respectively).
|
•
|
Higher revenues associated with the MEEIA energy efficiency program cost recovery mechanism ($10 million and $23 million, respectively) and lost revenue recovery mechanism ($11 million and $20 million, respectively), effective January 2013, which
increased
revenues by a combined
$21 million
and
$43 million
, respectively. 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 (
$3 million
and
$9 million
, respectively). See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.
|
•
|
Summer weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as cooling degree-days decreased 18% and 23%, respectively, which decreased revenues by
$59 million
and
$53 million
, respectively.
|
•
|
A reduction in revenues resulting from the Missouri Court of Appeals’ May 2013 decision that upheld the MoPSC's April 2011 order and a MoPSC order issued in July 2013. Ameren Missouri recorded a FAC prudence review charge for its estimated obligation to refund to its electric customers the earnings associated with certain long-term partial requirements sales previously recognized during the period from October 1, 2009, to May 31, 2011 (
$3 million
and
$25 million
, respectively). See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information regarding the FAC prudence review charge.
|
•
|
Absence in 2013 of a 2012 FERC-ordered Entergy refund that reduced purchased power expense that was not included in the FAC,
decreased
margins by
$24 million
for the
nine months ended September 30, 2013
, when compared with the same period in
2012
.
|
•
|
Winter weather conditions in
2013
were normal compared to warmer-than-normal conditions in
2012
, as heating degree-days increased 49%, which increased revenues by
$3 million
for the
nine months ended September 30, 2013
, compared with the same period in 2012.
|
•
|
Excluding the estimated impact of abnormal weather, revenues
increased
by
$2 million
, driven largely by higher natural gas transportation sales; however, total retail sales volumes decreased 3% for the
nine months ended
|
•
|
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
for the
nine months ended September 30, 2013
, when compared with the same period in 2012. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes.
|
•
|
Electric delivery service formula ratemaking adjustments resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA (
$52 million
and
$48 million
, respectively). The third quarter was favorably impacted by timing differences, increased rate base, a higher allowed return on equity, and absence of the collar adjustment impact on earnings which came into effect with the hot summer weather in 2012. The nine-month period was favorably impacted by increased rate base, a higher allowed return on equity, and absence of the collar adjustment.
|
•
|
Higher transmission revenues due to the forward-looking rate calculation for 2013 pursuant to a 2012 FERC order, whereas in 2012 rates were based on a historic base period (
$2 million
and
$18 million
, respectively). On January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement, which is subject to revenue requirement reconciliation.
|
•
|
Summer weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, as cooling degree-days decreased 20% and 23%, respectively, which decreased revenues by
$16 million
and
$15 million
, respectively. This excludes the impact of the collar adjustment discussed above.
|
•
|
A decrease in recovery of bad debt, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms (
$3 million
and
$7 million
,
|
•
|
Excluding the estimated impact of abnormal weather, total retail sales volumes decreased 6% and 3%, respectively, largely due to decreased sales in the commercial and industrial sectors (
$8 million
and
$11 million
, respectively).
|
•
|
Winter weather conditions in
2013
were normal compared to warmer-than-normal conditions in
2012
, as heating degree-days increased 39%, which increased revenues by
$11 million
for the
nine months ended September 30, 2013
, when compared with the same period in 2012.
|
•
|
An increase in recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms (
$1 million
and
$6 million
, respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs.
|
•
|
Increased gross receipts taxes due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by
$5 million
for the
nine months ended September 30, 2013
, compared with the same period in
2012
. 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
for the
nine months ended September 30, 2013
, when compared with the same period in 2012.
|
•
|
A $10 million increase in Ameren Missouri’s energy efficiency program costs due to the requirements of MEEIA, which became effective in base rates beginning in January 2013. These costs were offset by increased electric revenues recovered through customer billings, with no overall impact on net income.
|
•
|
A $10 million increase in employee benefit costs, primarily due to higher pension expense at Ameren Missouri because of a cost increase included in base rates as a result of the
|
•
|
A $4 million increase in non-storm-related distribution maintenance expenditures, primarily related to the timing of a circuit maintenance program at Ameren Illinois.
|
•
|
A $30 million increase in plant maintenance costs, primarily due to $38 million in costs for the scheduled 2013 Callaway energy center refueling and maintenance outage as there was no outage in 2012, partially offset by an $8 million reduction in costs due to fewer major boiler outages at coal-fired energy centers.
|
•
|
A $23 million increase in Ameren Missouri’s energy efficiency program costs due to the requirements of MEEIA, which became effective in base rates beginning in January 2013.
|
•
|
A $14 million increase in labor costs, primarily because of wage increases and Ameren Illinois staff additions to comply with the requirements of the IEIMA.
|
•
|
A $12 million increase in employee benefit costs, primarily due to higher pension expense at Ameren Missouri because of a cost increase included in base rates and increased amortization of prior-year pension deferrals both as a result of the 2012 MoPSC electric order. These increased expenses were offset by increased electric revenues recovered through customer billings, with no overall impact on net income.
|
•
|
A $10 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. For Ameren Missouri, a portion of these costs were offset by increased electric revenues recovered through customer billings. For Ameren Illinois, these costs are recoverable under provisions of the IEIMA.
|
•
|
A $5 million increase in Ameren Illinois natural gas operations and maintenance expenses, primarily because of expenses for pipeline integrity compliance.
|
•
|
A $5 million increase in Ameren Illinois energy efficiency and environmental remediation costs. These costs were offset by increased electric and natural gas revenues recovered through customer billings, with no overall impact on net income.
|
•
|
A $10 million increase in energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013.
|
•
|
A $5 million increase in employee benefit costs, primarily due to higher pension expense because of a cost increase included in base rates as a result of the 2012 MoPSC electric order. The increased expenses were offset by increased electric revenues recovered through customer billings, with no overall impact on net income.
|
•
|
A $30 million increase in plant maintenance costs, primarily due to $38 million in costs for the scheduled 2013 Callaway energy center refueling and maintenance outage as there was no outage in 2012, partially offset by an $8 million reduction in costs due to fewer major boiler outages at coal-fired energy centers.
|
•
|
A $23 million increase in energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013.
|
•
|
A $10 million increase in employee benefit costs, primarily due to higher pension expense because of a cost increase included in base rates and increased amortization of prior-year pension deferrals both as a result of the 2012 MoPSC electric order.
|
•
|
An $8 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. A portion of these costs, $5 million, were offset by increased electric revenues recovered through customer billings.
|
•
|
A $5 million increase in labor costs, primarily because of wage increases.
|
•
|
A $5 million increase in non-storm-related electric distribution maintenance expenditures, primarily related to the timing of the circuit maintenance program.
|
•
|
A $4 million increase in employee benefit costs, primarily due to higher medical expense resulting from increased headcount.
|
•
|
An $8 million increase in labor costs, primarily because of wage increases and staff additions to comply with the requirements of the IEIMA.
|
•
|
A $5 million increase in natural gas operations and maintenance expenses, primarily because of expenses for pipeline integrity compliance.
|
•
|
A $5 million increase in energy efficiency and environmental remediation costs. These costs were offset by increased electric and natural gas revenues recovered through customer billings, with no overall impact on net income.
|
•
|
A $4 million increase in non-storm-related electric distribution maintenance expenditures, primarily related to the timing of a circuit maintenance program.
|
•
|
A $2 million increase in storm-related repair costs, primarily due to major storms in 2013.
|
|
Three Months
|
|
Nine Months
|
||||||||
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||
Ameren
(a)
|
38
|
%
|
|
37
|
%
|
|
38
|
%
|
|
37
|
%
|
Ameren Missouri
(a)
|
38
|
%
|
|
38
|
%
|
|
37
|
%
|
|
38
|
%
|
Ameren Illinois
(a)
|
40
|
%
|
|
39
|
%
|
|
40
|
%
|
|
39
|
%
|
(a)
|
The provision for income taxes was based on the current estimate of the annual effective tax rate adjusted to reflect the tax impact of items discrete to the relevant period.
|
•
|
Lower sales prices, primarily due to the expiration of higher-priced hedges ($79 million and $205 million, respectively).
|
•
|
Increase in production volume and purchased power costs ($70 million and $143 million, respectively) driven by increased sales volumes and purchases for a large industrial customer.
|
•
|
A charge related to a sales and use tax settlement with the state of Illinois, which decreased margins by $7 million for the
nine months ended September 30, 2013
, compared with the same period in
2012
.
|
•
|
Higher sales volumes as a result of Marketing Company’s efforts to sell power to residential and small commercial customers in Illinois and a large industrial customer ($59 million and $134 million, respectively).
|
•
|
Net unrealized MTM activity on fuel-related contracts and nonqualifying power hedges, which increased margins by $24 million for the
nine months ended September 30, 2013
, compared with the same period in
2012
.
|
|
Net Cash Provided By
Operating Activities
|
|
Net Cash (Used In)
Investing Activities
|
|
Net Cash (Used In)
Financing Activities
|
||||||||||||||||||||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
2013
|
|
2012
|
|
Variance
|
|
2013
|
|
2012
|
|
Variance
|
||||||||||||||||||
Ameren
(a)
- continuing operations
|
$
|
1,215
|
|
|
$
|
1,090
|
|
|
$
|
125
|
|
|
$
|
(991
|
)
|
|
$
|
(839
|
)
|
|
$
|
(152
|
)
|
|
$
|
(296
|
)
|
|
$
|
(307
|
)
|
|
$
|
11
|
|
Ameren
(a)
- discontinued operations
|
99
|
|
|
222
|
|
|
(123
|
)
|
|
(42
|
)
|
|
(123
|
)
|
|
81
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||||
Ameren Missouri
|
781
|
|
|
699
|
|
|
82
|
|
|
(506
|
)
|
|
(521
|
)
|
|
15
|
|
|
(323
|
)
|
|
(247
|
)
|
|
(76
|
)
|
|||||||||
Ameren Illinois
|
507
|
|
|
441
|
|
|
66
|
|
|
(456
|
)
|
|
(304
|
)
|
|
(152
|
)
|
|
(50
|
)
|
|
(65
|
)
|
|
15
|
|
(a)
|
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
|
•
|
The absence of $138 million in premiums paid to bondholders in 2012 for the repurchase of the tendered principal of multiple series of Ameren Missouri and Ameren Illinois long-term debt notes.
|
•
|
An $89 million increase due to the cash flows associated with Ameren Missouri’s under-recovered FAC costs. Recoveries outpaced deferrals in 2013 by $36 million, while deferrals and refunds outpaced recoveries in 2012 by $53 million.
|
•
|
A $75 million increase due to changes in coal inventory levels at Ameren Missouri. During 2013, coal inventory levels were $47 million lower than year end because of delivery disruptions due to flooding, while in 2012, coal inventory levels increased $28 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions.
|
•
|
A $30 million increase in natural gas commodity over-recovered costs under the PGAs, primarily related to Ameren Illinois.
|
•
|
The absence 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 natural gas held in storage due to the changes in the market price for natural gas over the comparable periods.
|
•
|
Electric and natural gas margins, as discussed in Results of Operations,
increased
by
$17 million
, excluding impacts from the noncash IEIMA revenue requirement reconciliation adjustment and the May 2013 court order FAC prudence
|
•
|
A $19 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on Ameren Missouri and Ameren Illinois senior secured notes.
|
•
|
A net
$13 million
decrease
in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes at Ameren Illinois as well as 2013 credit rating upgrades.
|
•
|
A $13 million decrease in energy efficiency expenditures for Ameren Illinois customer programs that are recovered through customer billings over time.
|
•
|
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.
|
•
|
A $98 million increase in income tax payments. As discussed below, income tax payments at Ameren Missouri increased $58 million while income tax refunds at Ameren Illinois decreased $40 million. Considering both Ameren's continuing and discontinued operations, Ameren has made minimal federal income tax payments in 2013.
|
•
|
A $60 million increase in pension and postretirement benefit plan contributions primarily caused by the timing of payments in 2013 compared with 2012.
|
•
|
A $33 million increase in energy efficiency expenditures for Ameren Missouri customer programs that are recovered through customer billings over time.
|
•
|
A $33 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.
|
•
|
A $30 million increase in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, partially offset by unpaid liabilities as of December 31, 2011, pertaining to the fall 2011 outage that were paid in 2012. There was no refueling and maintenance outage in 2012.
|
•
|
A $21 million increase at Ameren Illinois associated with deferred recoveries of purchased power and transmission delivery pass-through costs.
|
•
|
A $20 million increase in property tax payments at Ameren Missouri caused by the timing of payments and higher assessed property tax values.
|
•
|
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, net of payments into that registry, as a result of a Missouri Court of Appeal ruling upholding the MoPSC's January 2009 electric rate order.
|
•
|
A $10 million increase in major storm restoration costs.
|
•
|
An $89 million increase due to the cash flows associated with under-recovered FAC costs. Recoveries outpaced deferrals in 2013 by $36 million, while deferrals and refunds outpaced recoveries in 2012 by $53 million.
|
•
|
A $75 million increase due to changes in coal inventory levels. During 2013, coal inventory levels were $47 million lower than year end because of delivery disruptions due to flooding, while in 2012, coal inventory levels increased $28 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions.
|
•
|
The absence of $62 million in premiums paid to bondholders in 2012 for the repurchase of the tendered principal of multiple series of long-term debt notes.
|
•
|
Electric and natural gas margins, as discussed in Results of Operations,
increased
by
$52 million
, excluding the impact from the noncash charge recorded in the first nine months of 2013 associated with the FAC prudence review charge.
|
•
|
The absence 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.
|
•
|
A $10 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on senior secured notes.
|
•
|
A $58 million increase in income tax payments resulting primarily from a reduction in accelerated depreciation deductions.
|
•
|
A $43 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.
|
•
|
A $33 million increase in energy efficiency expenditures for customer programs that are recovered through customer billings over time.
|
•
|
A $30 million increase in pension and postretirement benefit plan contributions primarily caused by the timing of payments in 2013 compared with 2012.
|
•
|
A $30 million increase in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, partially offset by unpaid liabilities as of December 31, 2011, pertaining to the fall 2011 outage, that were paid in 2012. There was no refueling and maintenance outage in 2012.
|
•
|
A $20 million increase in property tax payments caused by the timing of payments and higher assessed property tax values.
|
•
|
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, net of payments into that registry, as a result of a Missouri Court of Appeal ruling upholding the MoPSC's January 2009 electric rate order.
|
•
|
An $8 million increase in major storm restoration costs.
|
•
|
The absence of $76 million in premiums paid to bondholders in 2012 for the repurchase of the tendered principal of multiple series of long-term debt notes.
|
•
|
A $22 million increase in natural gas commodity over-recovered costs under the PGA.
|
•
|
A $20 million decrease in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers.
|
•
|
An $18 million decrease in natural gas held in storage due to the changes in the market price for natural gas over the comparable periods.
|
•
|
A $13 million decrease in energy efficiency expenditures for customer programs that are recovered through customer billings over time.
|
•
|
A $12 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on senior secured notes.
|
•
|
A net
$11 million
decrease
in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes as well as 2013 credit rating upgrades.
|
•
|
A one-time $7.5 million contribution, in 2012, to the Illinois Science and Energy Innovation Trust as required by the IEIMA.
|
•
|
Electric and natural gas margins, as discussed in Results of Operations,
decreased
by
$41 million
, excluding the impact from the noncash IEIMA revenue requirement reconciliation adjustment.
|
•
|
A $40 million decrease in income tax refunds resulting primarily from a reduction in accelerated depreciation deductions.
|
•
|
A $21 million increase associated with deferred recoveries of purchased power and transmission delivery pass-through costs.
|
|
Expiration
|
|
Borrowing Capacity
|
|
Credit Available
|
||||
Ameren
and Ameren Missouri:
|
|
|
|
|
|
||||
2012 Missouri Credit Agreement
(a)(b)
|
November 2017
|
|
$
|
1,000
|
|
|
$
|
1,000
|
|
Ameren and Ameren Illinois:
|
|
|
|
|
|
||||
2012 Illinois Credit Agreement
(a)(b)
|
November 2017
|
|
1,100
|
|
|
1,100
|
|
||
Ameren:
|
|
|
|
|
|
||||
Less:
|
|
|
|
|
|
||||
Letters of credit
|
|
|
(c)
|
|
|
(14
|
)
|
||
Total
|
|
|
$
|
2,100
|
|
|
$
|
2,086
|
|
(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 sublimits of Ameren Missouri and Ameren Illinois will mature and expire on March 31, 2014, and September 30, 2014, respectively, subject to extension on a 364-day basis or for a longer period upon notice by the respective borrower of receipt of any and all required federal or state regulatory approvals, as permitted under each credit agreement, but in no event later than November 14, 2017. In October 2013, Ameren Missouri and Ameren Illinois filed petitions seeking the state regulatory approval necessary to extend the maturity date of their borrowing sublimits under the 2012 Credit Agreements to November 14, 2017.
|
(c)
|
Not applicable.
|
|
|
|
Nine Months
|
||||||
|
Month Issued,
Repurchased or Matured
|
|
2013
|
|
2012
|
||||
Issuances
|
|
|
|
|
|
||||
Long-term debt
|
|
|
|
|
|
||||
Ameren Missouri:
|
|
|
|
|
|
||||
3.90% Senior secured notes due 2042
|
September
|
|
$
|
—
|
|
|
$
|
482
|
|
Ameren Illinois:
|
|
|
|
|
|
||||
2.70% Senior secured notes due 2022
|
August
|
|
—
|
|
|
400
|
|
||
Total Ameren long-term debt issuances
|
|
|
$
|
—
|
|
|
$
|
882
|
|
Redemptions, Repurchases and Maturities
|
|
|
|
|
|
||||
Long-term debt
|
|
|
|
|
|
||||
Ameren Missouri:
|
|
|
|
|
|
||||
5.25% Senior secured notes due 2012
|
September
|
|
—
|
|
|
173
|
|
||
6.00% Senior secured notes due 2018
|
September
|
|
—
|
|
|
71
|
|
||
6.70% Senior secured notes due 2019
|
September
|
|
—
|
|
|
121
|
|
||
5.10% Senior secured notes due 2018
|
September
|
|
—
|
|
|
1
|
|
||
5.10% Senior secured notes due 2019
|
September
|
|
—
|
|
|
56
|
|
||
Ameren Illinois:
|
|
|
|
|
|
||||
9.75% Senior secured notes due 2018
|
August
|
|
—
|
|
|
87
|
|
||
6.25% Senior secured notes due 2018
|
August
|
|
—
|
|
|
194
|
|
||
2000 Series A 5.50% pollution control revenue bonds due 2014
|
August
|
|
—
|
|
|
51
|
|
||
Total Ameren long-term debt redemptions, repurchases and maturities
|
|
|
$
|
—
|
|
|
$
|
754
|
|
|
Nine Months
|
||||||
|
2013
|
|
2012
|
||||
Ameren Missouri
|
$
|
320
|
|
|
$
|
300
|
|
Ameren Illinois
|
45
|
|
|
132
|
|
||
Dividends paid by Ameren
|
291
|
|
|
284
|
|
|
|
Moody’s
|
|
S&P
|
|
Fitch
|
Ameren:
|
|
|
|
|
|
|
Issuer/corporate credit rating
|
|
Baa3
|
|
BBB
|
|
BBB
|
Senior unsecured debt
|
|
Baa3
|
|
BBB-
|
|
BBB
|
Commercial paper
|
|
P-3
|
|
A-2
|
|
F2
|
Ameren Missouri:
|
|
|
|
|
|
|
Issuer/corporate credit rating
|
|
Baa2
|
|
BBB
|
|
BBB+
|
Secured debt
|
|
A3
|
|
A
|
|
A
|
Ameren Illinois:
|
|
|
|
|
|
|
Issuer/corporate credit rating
|
|
Baa2
|
|
BBB
|
|
BBB-
|
Secured debt
|
|
A3
|
|
A
|
|
BBB+
|
Senior unsecured debt
|
|
Baa2
|
|
BBB
|
|
BBB
|
•
|
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 July 2013, Illinois enacted a law called the Natural Gas Consumer, Safety and Reliability Act, that enables Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provide additional ICC oversight of natural gas utility performance. The law allows natural gas utilities the option to file, and requires the ICC to approve, a rate rider mechanism to provide for recovery of costs associated with certain categories of investment to improve the safety and reliability of the state’s natural gas infrastructure. Ameren Illinois expects to begin participation in this regulatory framework in 2014. Ameren Illinois anticipates it will increase its natural gas capital expenditures when it elects to participate in the new law’s regulatory framework.
|
•
|
In December 2012, the ICC issued an order with respect to Ameren Illinois' update IEIMA filing approving an electric delivery service revenue requirement that was a $70 million decrease from the requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The new rates became effective on January 1, 2013. These rates will impact Ameren Illinois’ cash flows during 2013, but not its operating revenues, which are instead impacted by the IEIMA’s 2013 revenue requirement reconciliation discussed below.
|
•
|
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. Consequently, Ameren Illinois' 2013 electric delivery service revenues will be based on its 2013 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2013 revenue requirement is expected to be higher than the 2012 revenue requirement due to expected increases in recoverable costs and rate base growth, even though the amount added to the monthly average yields of the 30-year United States treasury bonds decreased to 580 basis points in 2013 from 590 basis points in 2012.
|
•
|
In April 2013, Ameren Illinois filed its annual electric delivery formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. The update filing was revised based on the enactment of May 2013 amendments to the IEIMA. Pending ICC approval, the update filing, as filed by Ameren Illinois, would result in a $22 million decrease in Ameren Illinois’ electric delivery revenue requirement beginning in January 2014. The ICC staff has submitted testimony recommending a $42 million decrease in Ameren Illinois' electric delivery revenue requirement. An ICC decision with respect to the revised update filing is required in December 2013 and will establish rates for all of 2014. These rates will impact Ameren Illinois’
|
•
|
In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service. The current request, as revised in August 2013, seeks to increase annual revenues for natural gas delivery service by $47 million. The ICC staff is recommending a $28 million increase in Ameren Illinois’ annual revenues for natural gas service. In an attempt to reduce regulatory lag, Ameren Illinois used a future test year, 2014, in this proceeding. A decision in this proceeding is required in December 2013.
|
•
|
In December 2012, the MoPSC issued an order approving an increase in Ameren Missouri’s in annual electric revenues of $260 million, including $84 million related to an anticipated increase in normalized net energy costs above the net energy 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-energy costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The new rates became effective on January 2, 2013.
|
•
|
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 $147 million over three years for energy efficiency programs.
|
•
|
As they continue to experience cost 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 rate case in the second half of 2014. Ameren Missouri and Ameren Illinois will also seek legislative solutions to address cost recovery pressures. 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 baseload 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.
|
•
|
Ameren and Ameren Missouri 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 Missouri completed a scheduled refueling and maintenance outage at its Callaway energy center during the second quarter of 2013. The next scheduled refueling and maintenance outage will be in the fall of 2014. During a scheduled outage, which occurs every 18 months, maintenance expense will increase. 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 will decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, resulting in limited impact to earnings. Electric operating revenues in 2013 will 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. Environmental regulations, as well as future initiatives related to greenhouse gas emissions, could result in significant increases in capital expenditures and operating costs that 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 required capital expenditures for their continued operation.
|
•
|
Ameren continues to pursue its plans to invest in electric transmission. MISO has approved three electric transmission projects to 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. In August 2013, the ICC granted a certificate of public convenience and necessity and approved seven of nine sections of the route and three of the proposed nine substations for the project. In October 2013, the ICC granted ATXI’s request for a rehearing to consider additional evidence regarding the unapproved portions of the project. An order on rehearing is expected in March 2014. Right-of-way acquisitions for the approved portions of the project have begun with a full range of construction activities to begin 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 in its transmission expansion plan. These two projects are expected to be completed in 2018. The 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 projects as well as for the Big Muddy River project. The Big Muddy River project, located primarily in southern Illinois, may be evaluated for inclusion in MISO's future transmission expansion plans. Separate from the ATXI projects discussed above, Ameren Illinois expects 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 approved a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois' electric transmission business. Based on its forward-looking rate calculation, on January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement of $29 million. The increase in Ameren Illinois' transmission revenue requirement is subject to an annual revenue requirement reconciliation, which could result in an adjustment to revenues based on the actual revenue requirement in 2013.
|
•
|
For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, Taum Sauk matters, and separate FERC orders impacting Ameren Missouri and Ameren Illinois, see Note 3 - Rate and Regulatory Matters, and Note 10 - Commitments and Contingencies under Part I, Item 1, of this report and Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K.
|
•
|
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1 of this report for additional information. Under the terms of the transaction agreement, Ameren is required to operate its Merchant Generation business in the ordinary course through the transaction closing date, which is expected to occur by the end of 2013. However, if Ameren does not complete its divestiture of New AER, Ameren will continue to reduce, and ultimately eliminate, the Merchant Generation segment’s reliance on Ameren’s financial support.
|
•
|
Completion of the divestiture of New AER to IPH requires FERC and FCC approvals. In October 2013, Ameren received FERC approval for the divestiture of New AER to IPH. The FCC approval was received in August 2013. Separately, as a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same material terms as, AER’s variance of the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. On July 22, 2013, IPH, AER and Medina Valley, as current and future owners of the coal-fired energy centers, filed a request for a variance with the Illinois Pollution Control Board seeking materially the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision.
|
•
|
Immediately following receipt of FERC approval on October 11, 2013, Genco completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Medina Valley has entered into an agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. Ameren expects the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy
|
•
|
Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City, and Grand Tower gas-fired energy centers disposal group each met the criteria for discontinued operations presentation, Ameren suspended recording depreciation on these assets in March 2013.
|
•
|
Ameren’s divestiture of New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers may result in long-lived asset impairments, disposal-related losses, contingencies, reductions of existing deferred tax assets, and other consequences that are currently unknown.
|
•
|
Based on current projections for 2013, excluding the put option receipts, AER expects its operating cash flows to approximate its nonoperating cash flow requirements in 2013. Included in this 2013 projection, AER expects to receive income tax benefits through the tax allocation agreement with Ameren and its non-AER affiliates of $80 million. 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 through 2013.
|
•
|
In 2012, Marketing Company filed a notice with MISO of its intent to cease operations for one of the three units at AERG's E.D. Edwards energy center. MISO determined that AERG’s operation of that unit was required for system reliability purposes. This designation changes the pricing structure MISO uses to compensate Marketing Company for the operation of that one unit at the E.D. Edwards energy center. MISO and Marketing Company disagree on the level of revenue required to continue to have the unit available for reliability purposes. Ameren will not recognize any revenue related to this reliability contract for the E.D. Edwards unit until FERC rules on the appropriate compensation level. Depending on MISO’s reliability requirements, this rate structure could continue through 2016, although MISO could notify Marketing Company that it no longer needs the E.D. Edwards unit for reliability purposes and terminate the agreement after a 90-day notification. In July 2013, AERG submitted a series of filings with FERC requesting cost recovery, including depreciation expense, return on rate base costs, and associated taxes, to be included in the revenue requirement to continue to make the E.D. Edwards unit available for reliability purposes. In September 2013, MISO notified Marketing Company that this unit at the E.D. Edwards energy center would continue to be required for system reliability purposes through 2014. If Ameren’s ownership of AER continues through 2013, Ameren estimates it could record revenues of between $9 million and $22 million as a result of this reliability contract. Ameren will recover these revenues when they become probable, which may be after 2013.
|
•
|
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 million megawatthours in 2013, with approximately 95% of
|
•
|
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. The 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. Any unhedged forecasted generation will be exposed to market prices at the time of sale.
|
•
|
As of
September 30, 2013
, Marketing Company had sold forward approximately 28 million megawatthours for 2013, at an average price of $36 per megawatthour. Megawatthours sold forward in excess of Merchant Generation’s actual generation will be purchased from the market as needed.
|
•
|
As of
September 30, 2013
, for 2013, Merchant Generation had hedged fuel costs for approximately 26 million megawatthours of coal and up to 26 million megawatthours of base transportation at about $23 per megawatthour.
|
•
|
Upon the divestiture of New AER, the transaction agreement 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 and 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. See Note 9 - Related Party Transactions under Part I, Item 1, of this report for additional information.
|
•
|
Ameren anticipates the reduction in employees caused by the divestiture of New AER will result in a curtailment in its pension and postretirement benefit plans. Ameren anticipates the curtailment will result in a gain to reflect the removal of AER active employees who are not yet eligible to retire. The previously accrued liability for AER employees will remain in Ameren's pension and postretirement benefit plans; however, no additional benefits will be earned after closing.
|
•
|
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 use of continuing operating cash flows and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit as was the case at September 30, 2013, for Ameren. The working capital deficit of $209 million as of September 30, 2013, was primarily the result of current maturities of long-term debt, specifically Ameren’s $425 million 8.875% senior unsecured notes, Ameren Missouri’s $200 million 4.65% senior secured notes and $104 million 5.50% senior secured notes, and Ameren Illinois’ $150 million 8.875% senior secured notes, all of which will mature within the next twelve months. In October 2013, $44 million of Ameren
|
•
|
As of
September 30, 2013
, Ameren had $330 million in federal income tax net operating loss carryforwards (Ameren Missouri - $55 million and Ameren Illinois - $170 million) and $90 million in federal income tax credit carryforwards (Ameren Missouri - $12 million and Ameren Illinois - $- million). These federal income tax net operating loss carryforwards have been reduced by $80 million to reflect the reduction in net operating loss carryforwards that Ameren expects to utilize in 2013, as discussed in a separate bullet below. Consistent with the tax allocation agreement, these carryforwards are expected to partially offset 2013 income tax liabilities for Ameren Missouri, and into 2015 for Ameren and Ameren Illinois. These amounts exclude any additional net operating losses that will be generated by the New AER divestiture transaction. The tax benefits from these losses are currently recorded as a deferred tax asset on Ameren's balance sheet.
|
•
|
In December 2011, the Internal Revenue Service issued new guidance 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. Final regulations related to this guidance were issued in September 2013. These new rules are required to be implemented no later than January 1, 2014. Based on a preliminary evaluation of the new guidance, Ameren expects to utilize $40 million in federal income tax net operating loss carryforwards to offset tax liabilities related to the prescribed Internal Revenue Service accounting method change that we expect to file in 2014 in connection with this new guidance.
|
•
|
In April 2013, the Internal Revenue Service issued new guidance defining when expenditures to maintain, replace or improve steam or electric power generation property must be capitalized. This April 2013 guidance is expected to change how Ameren determines whether expenditures related to plant and equipment are deducted as repairs or capitalized for income tax purposes. Based on a preliminary evaluation of the new guidance, Ameren expects to utilize $80 million in federal income tax net operating loss carryforwards to offset tax liabilities related to the prescribed Internal Revenue Service accounting method change that will be filed 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. See Note 4 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the 2012 Credit
|
|
2013
|
|
2014
|
|
2015 - 2017
|
|||
Ameren:
|
|
|
|
|
|
|||
Coal
|
99
|
%
|
|
100
|
%
|
|
100
|
%
|
Coal transportation
|
100
|
|
|
98
|
|
|
98
|
|
Nuclear fuel
|
100
|
|
|
100
|
|
|
60
|
|
Natural gas for generation
|
100
|
|
|
14
|
|
|
8
|
|
Natural gas for distribution
(a)
|
73
|
|
|
26
|
|
|
7
|
|
Purchased power for Ameren Illinois
(b)
|
100
|
|
|
100
|
|
|
44
|
|
Ameren Missouri:
|
|
|
|
|
|
|||
Coal
|
99
|
%
|
|
100
|
%
|
|
100
|
%
|
Coal transportation
|
100
|
|
|
98
|
|
|
98
|
|
Nuclear fuel
|
100
|
|
|
100
|
|
|
60
|
|
Natural gas for generation
|
100
|
|
|
14
|
|
|
8
|
|
Natural gas for distribution
(a)
|
79
|
|
|
29
|
|
|
18
|
|
Ameren Illinois:
|
|
|
|
|
|
|||
Natural gas for distribution
(a)
|
72
|
%
|
|
25
|
%
|
|
5
|
%
|
Purchased power
(b)
|
100
|
|
|
100
|
|
|
44
|
|
(a)
|
Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2013 represents November 2013 through March 2014. The year 2014 represents November 2014 through March 2015. This continues each successive year through March 2018.
|
(b)
|
Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand.
|
Three Months Ended September 30, 2013
|
Ameren
|
|
Ameren
Missouri
|
|
Ameren
Illinois
|
||||||
Fair value of contracts at beginning of period, net
|
$
|
(126
|
)
|
|
$
|
25
|
|
|
$
|
(151
|
)
|
Contracts realized or otherwise settled during the period
|
11
|
|
|
(5
|
)
|
|
16
|
|
|||
Changes in fair values attributable to changes in valuation technique and assumptions
|
—
|
|
|
—
|
|
|
—
|
|
|||
Fair value of new contracts entered into during the period
|
—
|
|
|
—
|
|
|
—
|
|
|||
Other changes in fair value
|
(26
|
)
|
|
(5
|
)
|
|
(21
|
)
|
|||
Fair value of contracts outstanding at end of period, net
|
$
|
(141
|
)
|
|
$
|
15
|
|
|
$
|
(156
|
)
|
Nine Months Ended September 30, 2013
|
|
|
|
|
|
||||||
Fair value of contracts at beginning of year, net
|
$
|
(201
|
)
|
|
$
|
3
|
|
|
$
|
(204
|
)
|
Contracts realized or otherwise settled during the period
|
63
|
|
|
(7
|
)
|
|
70
|
|
|||
Changes in fair values attributable to changes in valuation technique and assumptions
|
—
|
|
|
—
|
|
|
—
|
|
|||
Fair value of new contracts entered into during the period
|
19
|
|
|
24
|
|
|
(5
|
)
|
|||
Other changes in fair value
|
(22
|
)
|
|
(5
|
)
|
|
(17
|
)
|
|||
Fair value of contracts outstanding at end of period, net
|
$
|
(141
|
)
|
|
$
|
15
|
|
|
$
|
(156
|
)
|
Sources of Fair Value
|
Maturity
Less than
1 Year
|
|
Maturity
1-3 Years
|
|
Maturity
4-5 Years
|
|
Maturity in
Excess of
5 Years
|
|
Total
Fair Value
|
||||||||||
Ameren:
|
|
|
|
|
|
|
|
|
|
||||||||||
Level 1
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4
|
)
|
Level 2
(a)
|
(41
|
)
|
|
(27
|
)
|
|
(1
|
)
|
|
—
|
|
|
(69
|
)
|
|||||
Level 3
(b)
|
19
|
|
|
(21
|
)
|
|
(20
|
)
|
|
(46
|
)
|
|
(68
|
)
|
|||||
Total
|
$
|
(24
|
)
|
|
$
|
(50
|
)
|
|
$
|
(21
|
)
|
|
$
|
(46
|
)
|
|
$
|
(141
|
)
|
Ameren Missouri:
|
|
|
|
|
|
|
|
|
|
||||||||||
Level 1
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4
|
)
|
Level 2
(a)
|
(3
|
)
|
|
(3
|
)
|
|
(1
|
)
|
|
—
|
|
|
(7
|
)
|
|||||
Level 3
(b)
|
26
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
26
|
|
|||||
Total
|
$
|
21
|
|
|
$
|
(5
|
)
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
15
|
|
Ameren Illinois:
|
|
|
|
|
|
|
|
|
|
||||||||||
Level 1
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Level 2
(a)
|
(38
|
)
|
|
(24
|
)
|
|
—
|
|
|
—
|
|
|
(62
|
)
|
|||||
Level 3
(b)
|
(7
|
)
|
|
(21
|
)
|
|
(20
|
)
|
|
(46
|
)
|
|
(94
|
)
|
|||||
Total
|
$
|
(45
|
)
|
|
$
|
(45
|
)
|
|
$
|
(20
|
)
|
|
$
|
(46
|
)
|
|
$
|
(156
|
)
|
(a)
|
Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed-price vs. floating over-the-counter natural gas swaps.
|
(b)
|
Principally power forward contract values based on information from external sources, historical results, and our estimates. Level 3 also includes option contract values based on a Black-Scholes model.
|
(a)
|
Evaluation of Disclosure Controls and Procedures
|
(b)
|
Changes in Internal Controls over Financial Reporting
|
•
|
the Illinois Pollution Control Board’s decision whether to grant a variance of the Illinois MPS requirements for the New AER energy centers to IPH, in connection with Ameren’s divestiture of New AER to IPH;
|
•
|
Medina Valley’s request for FERC approval to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital;
|
•
|
a wholesale customer’s lawsuit against Marketing Company alleging that certain assets related to the amended put option agreement may not be sold by Genco without their consent and that the impairment of assets recorded by Ameren (parent) in the fourth quarter of 2012, should reduce their billings;
|
•
|
Ameren Illinois’ appeal of the ICC’s 2012 electric distribution rate orders in its initial and update IEIMA filings;
|
•
|
a natural gas delivery service rate proceeding and an electric distribution formula update filing for Ameren Illinois pending before the ICC;
|
•
|
FERC litigation to determine wholesale distribution revenues for five of Ameren Illinois’ wholesale customers;
|
•
|
Entergy’s rehearing request of a May 2012 FERC order which required Entergy to refund to Ameren Missouri additional charges Ameren Missouri paid under an expired power purchase agreement;
|
•
|
Ameren Illinois’ rehearing request of FERC’s July 2012 and June 2013 orders regarding the inclusion of acquisition premiums in Ameren Illinois’ transmission rates;
|
•
|
ATXI's request for a certificate of public convenience and necessity and project approval from the ICC for the entire Illinois Rivers project;
|
•
|
the EPA’s Clean Air Act-related litigation filed against Ameren Missouri and NSR investigations at Genco and AERG;
|
•
|
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;
|
•
|
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.
|
|
AMEREN CORPORATION
(Registrant)
|
|
/s/ Martin J. Lyons, Jr.
|
Martin J. Lyons, Jr.
Executive Vice President and Chief Financial Officer
(Principal Financial Officer) |
|
|
UNION ELECTRIC COMPANY
(Registrant)
|
|
/s/ Martin J. Lyons, Jr.
|
Martin J. Lyons, Jr.
Executive Vice President and Chief Financial Officer
(Principal Financial Officer) |
|
|
AMEREN ILLINOIS COMPANY
(Registrant)
|
|
/s/ Martin J. Lyons, Jr.
|
Martin J. Lyons, Jr.
Executive Vice President and Chief Financial Officer
(Principal Financial Officer) |
1 Year Union Electric (PK) Chart |
1 Month Union Electric (PK) Chart |
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