AMEREN CORP, 8-K filed on 10/17/2013
Current report filing
Document And Entity Information (USD $)
12 Months Ended
Dec. 31, 2012
Jan. 31, 2013
Jun. 30, 2012
Document Type
8-K 
 
 
Amendment Flag
false 
 
 
Document Period End Date
Dec. 31, 2012 
 
 
Document Fiscal Year Focus
2012 
 
 
Document Fiscal Period Focus
FY 
 
 
Trading Symbol
AEE 
 
 
Entity Registrant Name
AMEREN CORP 
 
 
Entity Central Index Key
0001002910 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Entity Common Stock, Shares Outstanding
 
242,634,671 
 
Entity Voluntary Filers
No 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Public Float
 
 
$ 8,137,966,865 
Entity Well-known Seasoned Issuer
Yes 
 
 
Consolidated Statement Of Income (Loss) (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Operating Revenues:
 
 
 
Electric
$ 4,857 
$ 5,226 
$ 5,153 
Gas
924 
1,001 
1,116 
Total operating revenues
5,781 
6,227 
6,269 
Operating Expenses:
 
 
 
Fuel
714 
911 
673 
Purchased power
780 
952 
1,122 
Gas purchased for resale
472 
570 
668 
Other operations and maintenance
1,514 
1,580 
1,566 
Impairment and other charges
   
123 
64 
Depreciation and amortization
667 
646 
627 
Taxes other than income taxes
443 
434 
424 
Total operating expenses
4,590 
5,216 
5,144 
Operating Income
1,191 
1,011 
1,125 
Other Income and Expenses:
 
 
 
Miscellaneous income
70 
68 
88 
Miscellaneous expense
37 
23 
32 
Total other income
33 
45 
56 
Interest Charges
391 
387 
415 
Income Before Income Taxes
833 
669 
766 
Income taxes
309 
245 
274 
Income from Continuing Operations
524 
424 
492 
Income (Loss) from Discontinued Operations, Net of Taxes, (Note 16)
(1,498)
102 
(341)
Net Income (Loss)
(974)
526 
151 
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
 
 
 
Continuing Operations
6 
6 
9 
Discontinued Operations
(6)
1 
3 
Net Income (Loss) Attributable to Ameren Corporation:
 
 
 
Continuing Operations
518 
418 
483 
Discontinued Operations
(1,492)
101 
(344)
Net income (Loss) Attributable to Ameren Corporation
$ (974)
$ 519 
$ 139 
Earnings (Loss) per Common Share- Basic and Diluted:
 
 
 
Continuing Operations (in dollars per share)
$ 2.13 
$ 1.73 
$ 2.02 
Discontinued Operations (in dollars per share)
$ (6.14)
$ 0.42 
$ (1.44)
Net Income (Loss) per Common Share - Basic and Diluted
$ (4.01)
$ 2.15 
$ 0.58 
Dividends per Common Share
$ 1.600 
$ 1.555 
$ 1.540 
Average Common Shares Outstanding
242.6 
241.5 
238.8 
Consolidated Statement Of Comprehensive Income (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Other Comprehensive Income (Loss), Net of Taxes
$ 524 
$ 424 
$ 492 
Pension and other postretirement activity, net of income taxes (benefit)
(8)
(19)
10 
Comprehensive Income from Continuing Operations
516 
405 
502 
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests
6 
6 
9 
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation
510 
399 
493 
Income (Loss) from Discontinued Operations, Net of Income Taxes
(1,498)
102 
(341)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes
58 
(20)
(16)
Comprehensive Income (Loss) from Discontinued Operations
(1,440)
82 
(357)
Less: Comprehensive Income (Loss) from Discontinued Operations Attributable to Noncontrolling Interest
2 
(5)
1 
Comprehensive Income (Loss) from Discontinued Operations Attributed to Ameren Corporation
(1,442)
87 
(358)
Comprehensive Income (Loss) from Continuing Operations
$ (932)
$ 486 
$ 135 
Consolidated Statement Of Comprehensive Income (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Pension and other postretirement activity, tax (benefit)
$ (6)
$ (14)
$ 6 
Consolidated Balance Sheet (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Current Assets:
 
 
Cash and cash equivalents
$ 184 
$ 248 
Accounts receivable - trade (less allowance for doubtful accounts)
354 
424 
Unbilled revenue
291 
285 
Miscellaneous accounts and notes receivable
71 
48 
Materials and supplies
570 
550 
Current regulatory assets
247 
215 
Current accumulated deferred income taxes, net
170 
98 
Other current assets
98 
151 
Current assets of discontinued operations
1,600 
3,718 
Total current assets
3,585 
5,737 
Property, Plant and Equipment, Net
15,348 1
14,848 1
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
408 
357 
Goodwill
411 
411 
Intangible assets
14 
7 
Regulatory assets
1,786 
1,603 
Other assets
667 
760 
Total investments and other assets
3,286 
3,138 
TOTAL ASSETS
22,219 
23,723 
Current Liabilities:
 
 
Current maturities of long-term debt
355 
179 
Short-term debt
   
148 
Accounts and wages payable
533 
592 
Taxes accrued
50 
53 
Interest accrued
89 
91 
Customer deposits
107 
98 
Mark-to-market derivative liabilities
92 
122 
Current regulatory liabilities
100 
133 
Other current liabilities
168 
195 
Current liabilities of discontinued operations
1,166 
1,762 
Total current liabilities
2,660 
3,373 
Long-term Debt, Net
5,802 
5,853 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
3,176 
2,810 
Accumulated deferred investment tax credits
70 
76 
Regulatory liabilities
1,589 
1,502 
Asset retirement obligations
375 
364 
Pension and other postretirement benefits
1,138 
1,253 
Other deferred credits and liabilities
642 
424 
Total deferred credits and other liabilities
6,990 
6,429 
Commitments and Contingencies (Notes 2, 10, 14, 15 and 16)
   
   
Stockholders' Equity:
 
 
Common stock
2 
2 
Other paid-in capital
5,616 
5,598 
Retained earnings
1,006 
2,369 
Accumulated other comprehensive income (loss)
(8)
(50)
Total stockholders' equity
6,616 
7,919 
Noncontrolling Interests
151 
149 
Total equity
6,767 
8,068 
TOTAL LIABILITIES AND EQUITY
$ 22,219 
$ 23,723 
Consolidated Balance Sheet (Parenthetical) (USD $)
In Millions, except Per Share data, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Statement of Financial Position [Abstract]
 
 
Accounts receivable - trade, allowance for doubtful accounts
$ 17 
$ 20 
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
400.0 
400.0 
Common stock, shares outstanding
242.6 
242.6 
Consolidated Statement Of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Cash Flows From Operating Activities:
 
 
 
Net income (loss)
$ (974)
$ 526 
$ 151 
(Income ) Loss from discontinued operations, net of taxes
1,498 
(102)
341 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Impairment and other charges
   
123 
64 
Gain on sales of properties
   
(3)
(5)
Depreciation and amortization
627 
606 
590 
Amortization of nuclear fuel
83 
61 
54 
Amortization of debt issuance costs and premium/discounts
20 
16 
16 
Deferred income taxes and investment tax credits, net
260 
253 
384 
Allowance for equity funds used during construction
(36)
(34)
(52)
Stock-based compensation costs
29 
17 
15 
Other
(8)
(14)
1 
Changes in assets and liabilities:
 
 
 
Receivables
30 
200 
(232)
Materials and supplies
(25)
(27)
19 
Accounts and wages payable
(34)
(31)
23 
Taxes accrued
(3)
(5)
18 
Assets, other
(6)
59 
(47)
Liabilities, other
58 
(68)
88 
Pension and other postretirement benefits
(23)
(100)
(9)
Counterparty collateral, net
41 
36 
(70)
Premiums paid on long-term debt repurchases
(138)
   
   
Taum Sauk insurance recoveries, net of cost
   
(1)
54 
Net cash provided by operating activities - continuing operations
1,399 
1,512 
1,403 
Net cash provided by operating activities - discontinued operations
291 
366 
420 
Net cash provided by operating activities
1,690 
1,878 
1,823 
Cash Flows From Investing Activities:
 
 
 
Capital expenditures
(1,063)
(881)
(941)
Nuclear fuel expenditures
(91)
(62)
(68)
Purchases of securities - nuclear decommissioning trust fund
(403)
(220)
(271)
Sales and maturities of securities - nuclear decommissioning trust fund
384 
199 
256 
Proceeds from sales of properties
   
3 
7 
Tax grants received related to renewable energy properties
18 
   
   
Other
2 
12 
2 
Net Cash used in investing activities - continuing operations
(1,153)
(949)
(1,015)
Net cash used in investing activities - discontinued operations
(157)
(99)
(81)
Net cash used in investing activities
(1,310)
(1,048)
(1,096)
Cash Flows From Financing Activities:
 
 
 
Dividends on common stock
(382)
(375)
(368)
Dividends paid to noncontrolling interest holders
(6)
(6)
(8)
Short-term debt and credit facility repayments, net
(148)
(481)
(221)
Redemptions, repurchases, and maturities:
 
 
 
Long-term debt
(760)
(155)
(110)
Preferred stock
   
   
(52)
Issuances:
 
 
 
Long-term debt
882 
   
   
Common stock
   
65 
80 
Capital issuance costs
(16)
   
(9)
Generator advances received for construction
4 
5 
29 
Repayments of generator advances received for construction
   
(73)
(39)
Net cash used in financing activities - continuing operations
(426)
(1,020)
(698)
Net cash used in financing activities - discontinued operations
   
(100)
(106)
Net cash provided by (used in) financing activities
(426)
(1,120)
(804)
Net change in cash and cash equivalents
(46)
(290)
(77)
Cash and cash equivalents at beginning of year
255 
545 
622 
Cash and cash equivalents at end of year
209 
255 
545 
Less cash and cash equivalents of discontinued operations at end of year
25 
7 
7 
Cash and cash equivalents of continuing operations at end of year
184 
248 
538 
Noncash financing activity – dividends on common stock
(7)
   
   
Cash Paid (Refunded) During the Year:
 
 
 
Interest net of capitalized
433 
453 
494 
Income taxes, net
$ 1 
$ (61)
$ (92)
Consolidated Statement Of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Capitalized interest
$ 30 
$ 30 
$ 34 
Consolidated Statement Of Stockholders' Equity (USD $)
In Millions, unless otherwise specified
Total
Common Stock [Member]
Other Paid-In Capital [Member]
Retained Earnings [Member]
Derivative Financial Instruments [Member]
Deferred Retirement Benefit Costs [Member]
Accumulated Other Comprehensive Income (Loss) [Member]
Noncontrolling Interest [Member]
Total Ameren Corporation Stockholders' Equity [Member]
Beginning of year at Dec. 31, 2009
 
$ 2 
$ 5,412 
$ 2,455 
$ 10 
$ (23)
 
$ 204 
 
Beginning of year (shares) at Dec. 31, 2009
237.4 
 
 
 
 
 
 
 
 
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
 
 
 
Shares issued (value)
 
   
80 
 
 
 
 
 
 
Shares issued (number of shares)
3.0 
 
 
 
 
 
 
 
 
Stock-based compensation activity
 
 
14 
 
 
 
 
 
 
Regulatory recovery of prior-period common stock issuance costs
 
 
14 
 
 
 
 
 
 
Net income (loss) attributable to Ameren Corporation
139 
 
 
139 
 
 
 
 
 
Dividends
 
 
 
368 
 
 
 
 
 
Other
 
 
 
(1)
 
 
 
 
 
Change in derivative financial instruments
 
 
 
 
(10)
 
 
 
 
Change in deferred retirement benefit costs
(10)
 
 
 
 
6 
 
 
 
Net income attributable to noncontrolling interest holder
 
 
 
 
 
 
 
12 
 
Dividends paid to noncontrolling interest holders
 
 
 
 
 
 
 
8 
 
Redemptions of preferred stock
 
 
 
 
 
 
 
(52)
 
Other
 
 
 
 
 
 
 
(2)
 
Total stockholders' equity
 
 
 
 
 
 
 
 
7,730 
Stockholders' equity, end of year at Dec. 31, 2010
 
 
 
 
 
 
 
 
7,730 
End of year at Dec. 31, 2010
7,884 
2 
5,520 
2,225 
   
(17)
(17)
154 
 
End of year (shares) at Dec. 31, 2010
240.4 
 
 
 
 
 
 
 
 
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
 
 
 
Shares issued (value)
 
   
65 
 
 
 
 
 
 
Shares issued (number of shares)
2.2 
 
 
 
 
 
 
 
 
Stock-based compensation activity
 
 
13 
 
 
 
 
 
 
Regulatory recovery of prior-period common stock issuance costs
 
 
   
 
 
 
 
 
 
Net income (loss) attributable to Ameren Corporation
519 
 
 
519 
 
 
 
 
 
Dividends
 
 
 
375 
 
 
 
 
 
Other
 
 
 
   
 
 
 
 
 
Change in derivative financial instruments
 
 
 
 
7 
 
 
 
 
Change in deferred retirement benefit costs
19 
 
 
 
 
(40)
 
 
 
Net income attributable to noncontrolling interest holder
 
 
 
 
 
 
 
7 
 
Dividends paid to noncontrolling interest holders
 
 
 
 
 
 
 
6 
 
Redemptions of preferred stock
 
 
 
 
 
 
 
   
 
Other
 
 
 
 
 
 
 
(6)
 
Total stockholders' equity
7,919 
 
 
 
 
 
 
 
7,919 
Stockholders' equity, end of year at Dec. 31, 2011
7,919 
 
 
 
 
 
 
 
7,919 
End of year at Dec. 31, 2011
8,068 
2 
5,598 
2,369 
7 
(57)
(50)
149 
 
End of year (shares) at Dec. 31, 2011
242.6 
 
 
 
 
 
 
 
 
Beginning of year at Sep. 30, 2011
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
 
 
 
Net income (loss) attributable to Ameren Corporation1
25 
 
 
 
 
 
 
 
 
Total stockholders' equity
7,919 
 
 
 
 
 
 
 
7,919 
Stockholders' equity, end of year at Dec. 31, 2011
7,919 
 
 
 
 
 
 
 
7,919 
End of year at Dec. 31, 2011
8,068 
2 
5,598 
2,369 
7 
(57)
(50)
149 
 
End of year (shares) at Dec. 31, 2011
242.6 
 
 
 
 
 
 
 
 
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
 
 
 
Shares issued (value)
 
   
   
 
 
 
 
 
 
Shares issued (number of shares)
   
 
 
 
 
 
 
 
 
Stock-based compensation activity
 
 
18 
 
 
 
 
 
 
Regulatory recovery of prior-period common stock issuance costs
 
 
   
 
 
 
 
 
 
Net income (loss) attributable to Ameren Corporation
(974)
 
 
(974)
 
 
 
 
 
Dividends
 
 
 
389 
 
 
 
 
 
Other
 
 
 
   
 
 
 
 
 
Change in derivative financial instruments
 
 
 
 
18 
 
 
 
 
Change in deferred retirement benefit costs
8 
 
 
 
 
24 
 
 
 
Net income attributable to noncontrolling interest holder
 
 
 
 
 
 
 
   
 
Dividends paid to noncontrolling interest holders
 
 
 
 
 
 
 
6 
 
Redemptions of preferred stock
 
 
 
 
 
 
 
   
 
Other
 
 
 
 
 
 
 
8 
 
Total stockholders' equity
6,616 
 
 
 
 
 
 
 
6,616 
Stockholders' equity, end of year at Dec. 31, 2012
6,616 
 
 
 
 
 
 
 
6,616 
End of year at Dec. 31, 2012
6,767 
2 
5,616 
1,006 
25 
(33)
(8)
151 
 
End of year (shares) at Dec. 31, 2012
242.6 
 
 
 
 
 
 
 
 
Beginning of year at Sep. 30, 2012
 
 
 
 
 
 
 
 
 
Increase (Decrease) in Stockholders' Equity [Roll Forward]
 
 
 
 
 
 
 
 
 
Net income (loss) attributable to Ameren Corporation1
(1,156)
 
 
 
 
 
 
 
 
Total stockholders' equity
6,616 
 
 
 
 
 
 
 
6,616 
Stockholders' equity, end of year at Dec. 31, 2012
6,616 
 
 
 
 
 
 
 
6,616 
End of year at Dec. 31, 2012
$ 6,767 
 
 
 
 
 
$ (8)
 
 
End of year (shares) at Dec. 31, 2012
242.6 
 
 
 
 
 
 
 
 
Summary Of Significant Accounting Policies
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.
•
Union Electric Company, or Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Ameren Missouri was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri. This area has an estimated population of 2.8 million and includes the Greater St. Louis area. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.
•
Ameren Illinois Company, or Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois was created by the merger of CILCO and IP with and into CIPS. CIPS was incorporated in Illinois in 1923 and is successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to portions of central and southern Illinois having an estimated population of 3.1 million in an area of 40,000 square miles. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 806,000 customers.
•
AER consists of non-rate-regulated operations, including Genco, AERG, Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding the divestiture.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services.
In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren’s analysis of the current and projected future financial condition of its Merchant Generation business segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this business segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation business segment’s, including Genco's, reliance on Ameren’s financial support and shared services support. Furthermore, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying values of the Merchant Generation energy centers, except for the Joppa coal-fired energy center, to their estimated fair values. See Note 16 - Divestiture Transactions and Discontinued Operations.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH, which Ameren expects will occur in the fourth quarter of 2013. Immediately prior to Ameren's entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which was subject to FERC approval. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and Genco's sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Ameren expects a third-party sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers will be completed by the end of 2013. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding these divestitures. As a result of the transaction agreement with IPH and Ameren's plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation beginning on March 14, 2013. Therefore, Ameren has segregated New AER's and the Elgin, Gibson City, and Grand Tower gas-fired energy centers' operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise noted, these notes to the financial statements have been revised to exclude discontinued operations for all periods presented. All other information herein remains unchanged. The information contained herein does not modify or update the disclosures contained in Ameren's Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 1, 2013, in any way, nor does it reflect any subsequent information or events, other than as required to reflect the results of the discontinued operations presentation described above. Information presented for the Ameren Missouri and Ameren Illinois registrants also remains unchanged. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation.
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, Ameren Missouri and Ameren Illinois defer certain costs as assets pursuant to actions of rate regulators or because of expectations that the companies will be able to recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts as liabilities pursuant to actions of rate regulators or based on the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. In addition to the cost recovery mechanisms discussed in the Purchased Gas, Power and Fuel Rate-adjustment Mechanisms section below, Ameren Missouri and Ameren Illinois have approvals from regulators to use other cost recovery mechanisms. Ameren Missouri has a vegetation management and infrastructure inspection cost tracker, pension and postretirement benefit cost tracker, uncertain tax positions tracker, renewable energy standards cost tracker, and, starting in 2013, a storm restoration cost tracker and the MEEIA energy efficiency cost recovery mechanisms. Ameren Illinois has an environmental cost rider, asbestos-related litigation rider, energy efficiency rider, and a bad debt rider. See Note 2 - Rate and Regulatory Matters for additional information on regulatory assets and liabilities. In addition, other costs that Ameren Missouri and Ameren Illinois expect to recover from customers are recorded as construction work in progress and property and plant, net. See Note 3 - Property and Plant, Net.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Allowance for Doubtful Accounts Receivable
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has a rate mechanism that adjusts rates for bad debt expense above or below those being collected in rates.
Materials and Supplies
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate. The following table presents a breakdown of materials and supplies at December 31, 2012, and 2011:
 
 
2012
 
Fuel(a)
$
198

Gas stored underground
131

Other materials and supplies
241

 
$
570

2011
 
Fuel(a)
$
150

Gas stored underground
171

Other materials and supplies
229

 
$
550

(a)
Consists of coal, oil, paint, propane, and tire chips.
Property and Plant
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 - Property and Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property. The provision for depreciation for the Ameren Companies in 2012, 2011 and 2010 ranged from 3% to 4% of the average depreciable cost.
Allowance for Funds Used During Construction
In our rate-regulated operations, we capitalize the allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, as is the utility industry's accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing during construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates. The annual allowance for funds used during construction rates that were utilized during 2012, 2011 and 2010 were 8% to 9% for all years.
Goodwill and Intangible Assets
Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of December 31, 2012, Ameren’s goodwill related to the acquisitions of IP in 2004 and of CILCORP in 2003.
Ameren has three reporting units, which also represent Ameren’s reportable segments. Ameren's reporting units are Ameren Missouri, Ameren Illinois, and Merchant Generation. Ameren’s reporting units have been defined and goodwill has been evaluated at the operating segment level in accordance with authoritative accounting guidance. Our reporting units represent businesses for which discrete financial information is available and reviewed regularly by management. All of Ameren's goodwill at December 31, 2012, and 2011 has been assigned to the Ameren Illinois reporting unit.
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Ameren applied a qualitative goodwill evaluation model for its annual goodwill impairment test conducted as of October 31, 2012. Based on the results of Ameren’s qualitative assessment, Ameren believes it was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value as of October 31, 2012, indicating no impairment of Ameren’s goodwill. The following factors, not meant to be all-inclusive, were considered by Ameren when assessing whether it was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value for the October 31, 2012, test:
•
Macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;
•
Pending rate case outcomes and future rate case outcomes;
•
Changes in laws and potential law changes;
•
Observable industry market multiples;
•
Achievement of IEIMA performance metrics and the yield of the 30-year United States treasury bonds; and
•
Actual and forecasted financial performance.
The goodwill assigned to the Ameren Illinois reporting unit on Ameren's December 31, 2012 consolidated balance sheet had no accumulated goodwill impairment losses. Ameren will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, and observable industry market multiples of the Ameren Illinois reporting unit for signs of possible declines in estimated fair value and potential goodwill impairment.
Intangible Assets. Ameren classifies emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At December 31, 2012, Ameren’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s renewable energy credits was $14 million and $7 million at December 31, 2012, and 2011, respectively.
Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. Ameren recorded amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, of $4 million, $3 million, and $13 million during the years ended December 31, 2012, 2011, and 2010, respectively.
During 2011, Ameren recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowances, which had no impact on earnings. The impairment was triggered by a significant observable decline in the market price of SO2 and NOX allowances used for CAIR compliance.
Impairment of Long-lived Assets
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell. See Note 16 - Divestiture Transactions and Discontinued Operations and Note 17 - Impairment and Other Changes for additional information about Ameren’s long-lived asset impairments.
Investments
Ameren evaluates for impairment the investments held in Ameren Missouri's nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which Ameren believes would be recovered in electric rates paid by its customers. Accordingly, Ameren recognizes a regulatory asset on its consolidated balance sheet for losses on investments held in the nuclear decommissioning trust fund. See Note 9 - Nuclear Decommissioning Trust Fund Investments for additional information.
Environmental Costs
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
Unamortized Debt Discount, Premium, and Expense
Discount, premium, and expense associated with long-term debt are amortized over the lives of the related issues.
Revenue
The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period.
Beginning in 2012, Ameren Illinois elected to participate in performance-based formula ratemaking framework pursuant to the IEIMA. The IEIMA provides for an annual reconciliation of Ameren Illinois' electric distribution revenue requirement. As of each balance sheet date, Ameren Illinois records its best estimate of the electric distribution revenue impact resulting from the reconciliation of the revenue requirement necessary to reflect the actual costs incurred for that year with the revenue requirement that was in effect for that year. If the current year's revenue requirement is greater than the revenue requirement customer rates were based upon, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional costs from customers within the next two years. If the current year's revenue requirement is less than the revenue requirement customer rates were based upon, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within the next two years. See Note 2 - Rate and Regulatory Matters for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.
Beginning in 2013, Ameren Illinois will record the impact of a revenue requirement reconciliation for its electric transmission jurisdiction, pursuant to FERC-approved rate treatment.
Nuclear Fuel
Ameren Missouri’s cost of nuclear fuel is capitalized and then amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated and sold, and that cost is charged to "Operating Expenses - Fuel" in the consolidated statement of income (loss).
Purchased Gas, Power and Fuel Rate-adjustment Mechanisms
Ameren Missouri and Ameren Illinois have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs. See Note 2 - Rate and Regulatory Matters for the regulatory assets and liabilities recorded at December 31, 2012, and 2011, related to the rate-adjustment mechanisms discussed below.
In Ameren Missouri’s and Ameren Illinois’ retail natural gas utility jurisdictions, changes in natural gas costs are reflected in billings to their natural gas utility customers through PGA clauses. The differences between actual natural gas costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to natural gas utility customers in a subsequent period.
In Ameren Illinois’ retail electric utility jurisdictions, changes in purchased power costs and transmission service cost are reflected in billings to their electric utility customers through pass-through rate-adjustment clauses. The differences between actual purchased power and transmission service costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to electric utility customers in a subsequent period.
Ameren Missouri has a FAC that allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel, certain fuel additives, emission allowances, purchased power costs, transmission costs, and MISO costs and revenues, net of off-system revenues, greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudency review. The differences between the cost of fuel incurred and the cost of fuel recovered from Ameren Missouri customers' base rates are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to Ameren Missouri’s electric utility customers in a subsequent period. The MoPSC's December 2012 electric rate order changed the FAC to include activated carbon, limestone and urea costs, along with transmission revenues starting in 2013.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. We record net purchases in a single hour in “Operating Expenses - Purchased power” and net sales in a single hour in “Operating Revenues - Electric” in our statements of income (loss). On occasion, prior-period transactions will be resettled outside the routine settlement process because of a change in MISO’s tariff or a material interpretation thereof. In these cases, the Ameren Companies recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated, and the Ameren Companies recognize revenues once the resettlement amount is received.
Stock-based Compensation
Stock-based compensation cost is measured at the grant date based on the fair value of the award. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite service period. See Note 12 - Stock-based Compensation for additional information.
Excise Taxes
Excise taxes levied on us are reflected on Ameren Missouri customer electric bills and on Ameren Missouri and Ameren Illinois customer natural gas bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the consolidated statement of income (loss). Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the customer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in “Taxes accrued” on the consolidated balance sheet. Ameren recorded excise taxes in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” of $193 million, $194 million, and $189 million for the years ended December 31, 2012, 2011, and 2010, respectively.
Income Taxes
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
We recognize that regulators will probably reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded because of decreases in the statutory rate, have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery in rates of future income taxes, resulting principally from the reversal of allowance for funds used during construction. This refers to equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of the authoritative accounting guidance for income taxes.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 - Income Taxes.
For certain renewable energy construction projects placed in service in 2010 and 2012, Ameren Missouri elected to seek federal cash tax grants in lieu of investment tax credits for which the projects also qualified.  These grants were accounted for using a grant recognition accounting model.  Ameren Missouri elected to reduce the basis of property as cash grants are received, which will reduce the amount of depreciation expense recognized in future periods.  In 2012, Ameren Missouri received $18 million in federal cash tax grants.
Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution of capital to the party receiving the benefit.
Noncontrolling Interests
Ameren’s noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren’s subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.
Earnings per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2012, 2011, and 2010. The number of dilutive stock options, restricted stock shares, and performance share units had an immaterial impact on earnings per share. There were no assumed stock option conversions in 2010, as the remaining stock options were not dilutive. All of Ameren’s stock options expired in February 2010.
Accounting Changes and Other Matters
The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact the Ameren Companies.
Disclosures about Fair Value Measurements
In May 2011, FASB issued additional authoritative guidance regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect Ameren's results of operations, financial position, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2012. See Note 8 - Fair Value Measurements for the required additional disclosures.
Presentation of Comprehensive Income
In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect Ameren's results of operations, financial position, or liquidity.
In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. The amendments will not affect Ameren's results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2013 on a prospective basis.
Disclosures about Offsetting Assets and Liabilities
In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments will not affect Ameren's results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2013 with retrospective application required.
Asset Retirement Obligations
Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. Ameren has recorded AROs for retirement costs associated with Ameren Missouri for the Callaway energy center decommissioning costs, CCR storage facilities, and river structures. Also, Ameren has recorded AROs for retirement costs associated with Ameren Missouri and Ameren Illinois for asbestos removal and the disposal of certain transformers. After the New AER divestiture is complete, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers.
Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Note 2 - Rate and Regulatory Matters.
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2012 and 2011:
 
Ameren(a)
 
Balance at December 31, 2010
$
403

 
Liabilities incurred
—

 
Liabilities settled
(2
)
 
Accretion in 2011(b)
22

 
Change in estimates(c)
(54
)
 
Balance at December 31, 2011
$
369

(d) 
Liabilities incurred
—

 
Liabilities settled
(6
)
 
Accretion in 2012(b)
20

 
Change in estimates(e)
(8
)
 
Balance at December 31, 2012
$
375

 
(a)
The nuclear decommissioning trust fund assets of 408 million and 357 million as of December 31, 2012, and 2011, respectively, were restricted for decommissioning of the Callaway energy center.
(b)
Accretion expense was recorded as an increase to regulatory assets.
(c)
Ameren changed its fair value estimate related to its Callaway energy center decommissioning costs because of a cost study performed in 2011 and a decline in the cost escalation factor assumptions. Additionally, Ameren changed the fair value estimates related to retirement costs for asbestos removal, river structures and CCR storage facilities.
(d)
Balance included $5 million in "Other current liabilities" on the consolidated balance sheet as of December 31, 2011.
(e)
Ameren changed the fair value estimates for asbestos removal. The estimates for asbestos removal costs at Hutsonville and Meredosia energy centers decreased because less asbestos than anticipated was found in the energy centers' structures during reviews made after the closure of these energy centers, and because removal was more cost efficient than anticipated due to the closure.
Employee Separation Charges
During the fourth quarter of 2011, as part of efforts to reduce operations and maintenance expenses, Ameren Missouri and Ameren Services extended voluntary separation offers consistent with Ameren's standard management separation program to eligible management and labor union-represented employees. Approximately 340 employees of Ameren Missouri and Ameren Services accepted the offers and left their employment by December 31, 2011. Ameren recorded a pretax charge to earnings of $28 million for the severance costs related to these offers. These charges were recorded in “Other operations and maintenance" expense in the consolidated statement of income (loss) for the year ended December 31, 2011. Substantially all of the severance costs were paid in the first quarter of 2012 and were recorded in “Accounts and wages payable” on the consolidated balance sheet at December 31, 2011.
In 2011, the Meredosia and Hutsonville energy centers initiated separation programs to reduce positions under the terms and benefits consistent with Ameren's standard management separation program. Ameren recorded pretax charges related to these programs of $4 million in 2011. The charge was recorded in "Impairment and other charges" on the consolidated statement of income (loss). See Note 17 - Impairment and Other Charges for additional information.
Rate And Regulatory Matters
RATE AND REGULATORY MATTERS
RATE AND REGULATORY MATTERS
Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.
Missouri
2009, 2010, and 2011 Electric Rate Orders
Noranda, Ameren Missouri's largest electric customer, and the MoOPC appealed certain aspects of the MoPSC's January 2009 electric rate order to the Stoddard County Circuit Court. In September 2009, the Stoddard County Circuit Court issued a stay of the electric order as it applied specifically to Noranda's electric service account, which allowed Noranda to pay a portion of its monthly billings into the Stoddard County Circuit Court's registry until the court ultimately rendered a decision on the appeal. In August 2010, the Stoddard County Circuit Court issued a judgment that reversed part of the MoPSC's January 2009 electric rate order. However, upon issuance, the Stoddard County Circuit Court suspended its own judgment. Ameren Missouri appealed the Stoddard County Circuit Court's judgment and, in November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC's January 2009 electric rate order. In March 2012, the Stoddard County Circuit Court released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21 million, reducing the previously recorded trade accounts receivable.
In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $230 million. The MIEC, MoOPC, and four industrial customers appealed certain aspects of the MoPSC's May 2010 electric rate order to the Cole County Circuit Court. In December 2010, the Cole County Circuit Court issued a stay of the electric order as it applied specifically to four industrial customers' electric service accounts, which allowed them to pay a portion of their monthly billings into the Cole County Circuit Court's registry until the court ultimately rendered a decision on the appeal. In May 2012, the Cole County Circuit Court issued a ruling that upheld the MoPSC's May 2010 electric rate order and released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $16 million, reducing the previously recorded trade accounts receivable.
In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million, including $52 million related to an increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. The MoPSC's July 2011 electric rate order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result, Ameren recorded in 2011 a pretax charge to earnings of $89 million. Ameren recorded the charge to “Impairment and other charges.” See Note 17 - Impairment and Other Charges for additional information. In July 2012, the Missouri Court of Appeals upheld the MoPSC's July 2011 electric rate order. Ameren Missouri did not seek further appeal of the MoPSC order.
2012 Electric Rate Order
In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million, including $84 million related to an anticipated increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its July 2011 electric rate order. The annual increase request also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other nonfuel costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The revenue increase was based on a 9.8% return on equity, a capital structure composed of 52.3% common equity, and a rate base of $6.8 billion.
The MoPSC approved Ameren Missouri's continued use of its FAC, with no change to its 95% sharing percentage, but with a modification relating to transmission revenues. Transmission revenues previously included in base rates will be included in the FAC prospectively. This change resulted in the portion of the rate increase attributed to net fuel costs being reduced, and the portion attributed to other nonfuel costs being increased, by $33 million as compared to base rates authorized in the MoPSC's July 2011 electric rate order. This change in regulatory treatment will have no immediate impact on earnings. Transmission charges that had previously been included in the FAC remain in the FAC. Further, the order clarified that changes in costs for activated carbon, limestone and urea are included in the FAC. The MoPSC order approved the continued use of Ameren Missouri's vegetation management and infrastructure inspection cost tracker, pension and postretirement benefit cost tracker, renewable energy standards cost tracker, and the uncertain tax positions tracker.
The order also established a storm restoration cost tracking mechanism to facilitate the recovery in future rate cases of storm costs that vary from those included in rates and allowed retention of the refund received in June 2012 from Entergy related to a power purchase agreement that existed prior to the implementation of the FAC. See below under Federal for additional information about this refund, which remains subject to appeal, and Ameren Missouri's power purchase agreement with Entergy. However, the MoPSC did not approve Ameren Missouri's request for plant-in-service accounting treatment for assets placed in service between rate cases or recovery of its 2011 severance costs.
Rate changes consistent with the order became effective on January 2, 2013. In January 2013, Ameren Missouri appealed the amount of property taxes included in the 2012 electric rate order to the Missouri Court of Appeals, Western District. In February 2013, the MoOPC, the MIEC and others filed separate appeals to the Missouri Court of Appeals, Western District, relating to the 2012 electric rate order's treatment of transmission costs in the FAC and other items. A decision is expected by the Missouri Court of Appeals, Western District, in 2013. Ameren Missouri cannot predict the ultimate outcome of its appeal.
MEEIA Order
The MEEIA established a regulatory framework that, among other things, allows electric utilities to recover costs related to MoPSC-approved energy efficiency programs. The law requires the MoPSC to ensure that a utility's financial incentives are aligned to help customers use energy more efficiently, to provide timely cost recovery, and to provide earnings opportunities associated with cost-effective energy efficiency programs. Missouri does not have a law mandating energy efficiency standards.
The MoPSC's December 2012 electric rate order approved Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs, and associated cost recovery mechanisms and incentive awards. Beginning in 2013, Ameren Missouri will invest approximately $147 million over the next three years for energy efficiency programs. The order allows for Ameren Missouri to collect its program costs and 90% of its projected lost revenue from customers over the same three years starting on January 2, 2013. The remaining 10% of projected lost revenue is expected to be recovered as part of future rate proceedings.
Additionally, the order provides for an incentive award that would allow Ameren Missouri to earn additional revenues based on achievement of certain energy efficiency goals, including approximately $19 million if 100% of its energy efficiency goals are achieved during the three-year period, with the potential to earn more if Ameren Missouri's energy savings exceed those goals. Ameren Missouri must achieve at least 70% of its energy efficiency goals before it earns any incentive award. The recovery of the incentive award from customers, if the energy efficiency goals are achieved, would begin after the three-year energy efficiency plan is complete and upon the effective date of an electric service rate order or potentially with the future adoption of a rider mechanism.
FAC Prudence Review
Missouri law requires the MoPSC to perform prudence reviews of Ameren Missouri's FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren recorded a pretax charge to earnings of $18 million, including $1 million for interest, in 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren during the period from March 1, 2009, to September 30, 2009.
Ameren Missouri disagrees with the MoPSC order's classification of these sales and believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. In May 2012, upon appeal by Ameren Missouri, the Cole County Circuit Court reversed the MoPSC's April 2011 order. In June 2012, the MoPSC filed an appeal of the Cole County Circuit Court's ruling to the Missouri Court of Appeals, Western District. Ameren Missouri has not recorded additional revenues as a result of the Cole County Circuit Court's May 2012 ruling, as the MoPSC's appeal to the Missouri Court of Appeals is ongoing. A decision is expected to be issued in 2013.
In February 2012, the MoPSC staff issued its FAC review report for the period from October 1, 2009, to May 31, 2011. In its report, the MoPSC staff asked the MoPSC to direct Ameren Missouri to refund to customers the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. Missouri law does not impose a specific deadline by which the MoPSC must complete its prudence reviews. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probable of refund to customers.
Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. We cannot predict the ultimate outcome of these regulatory or judicial proceedings. If the courts ultimately rule in favor of Ameren Missouri's position regarding the classification of the long-term partial requirements sales, Ameren Missouri would not seek to recover from customers the sum that would be covered by the accounting authority order, if it is granted.
Regional Transmission Organization
Ameren Missouri is a transmission-owning member of MISO. In April 2012, the MoPSC authorized Ameren Missouri's continued conditional MISO participation through May 2016, including the condition that Ameren Missouri later file a further study with the MoPSC that evaluates the costs and benefits of Ameren Missouri's continued participation in MISO, as it has periodically done since its MISO participation began in 2003. The next cost benefit study is required to be filed with the MoPSC in November 2015.
Illinois
IEIMA
Ameren Illinois' initial filing to participate in the performance based formula ratemaking process under the IEIMA was based on 2010 recoverable costs and expected net plant additions for 2011 and 2012. In September 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $779 million, which was a $55 million decrease from the electric delivery service revenue requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The rates became effective on October 19, 2012, and were effective through the end of 2012. In October 2012, Ameren Illinois filed an appeal of the ICC's initial filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Ameren Illinois believes that the ICC has incorrectly implemented the IEIMA by using an average rate base as opposed to a year-end rate base in setting rates, through its treatment of accumulated deferred income taxes, and through the method it used for calculating the equity portion of Ameren Illinois' capital structure and the method for calculating interest on the revenue requirement reconciliation and return on equity collar. The ICC's September 2012 order jeopardizes Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Until the uncertainty surrounding how the Illinois law will ultimately be implemented is removed, Ameren Illinois is slowing IEIMA capital spending with a corresponding negative effect on the job creation that the legislature sought to effectuate with the law. Although Ameren Illinois intends to meet its IEIMA capital spending requirements, it is proceeding on a slower investment schedule than previously contemplated.
In April 2012, Ameren Illinois submitted to the ICC an update filing under IEIMA based on 2011 recoverable costs and expected net plant additions for 2012. In December 2012, the ICC issued an order approving an Ameren Illinois electric delivery service revenue requirement of $764 million, which is a $15 million decrease in the revenue requirement allowed in the ICC initial filing order. The rates became effective on January 1, 2013, and will be effective through the end of 2013. In January 2013, Ameren Illinois filed an appeal of the ICC's update filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013.
Ameren Illinois will submit to the ICC, during the second quarter of 2013, an update filing based on 2012 recoverable costs and expected net plant additions for 2013, which will determine rates that are effective during 2014.
Ameren Illinois' 2012 electric delivery service revenues were based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2012 revenue requirement under the IEIMA's formula ratemaking framework was lower than the revenue requirement included in both the ICC's 2010 electric rate order and the ICC's September 2012 order related to Ameren Illinois' initial IEIMA filing. As a result, Ameren recorded a $55 million regulatory liability with a corresponding decrease in electric revenues to represent its estimate of the probable decrease in electric delivery service revenues expected to be approved by the ICC in December 2013 to provide Ameren Illinois recovery of all prudently and reasonably incurred costs and an earned rate of return on common equity for 2012. Any decrease in electric delivery service revenues approved by the ICC in December 2013 will be refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA.
In December 2012, the ICC approved Ameren Illinois' advanced metering infrastructure deployment plan, which outlines how Ameren Illinois will comply with the IEIMA requirement to spend $360 million on smart grid assets over ten years on a cost-beneficial basis to its electric customers. The plan targets the second quarter of 2014 to begin installation of smart meters.
2013 Natural Gas Delivery Service Rate Case
On January 25, 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by $50 million. The request was based on a 10.4% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $1.1 billion. In an attempt to reduce regulatory lag, Ameren Illinois is using a future test year of 2014 in this proceeding.
Also in its filing, Ameren Illinois is requesting an increase in the percentage of costs to be recovered through a fixed non-volumetric customer charge from 80% to 85% for all residential customers and most commercial customers.
A decision by the ICC in this proceeding is required by December 2013. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve, when any rate changes may go into effect, or whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect. 
ATXI Transmission Project
ATXI's Illinois Rivers project is a MISO-approved project that involves building a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. In 2012, ATXI made a filing with the ICC requesting a certificate of public convenience and necessity and project approval. A decision is expected by the ICC in 2013. A certificate of public convenience and necessity is required before ATXI can proceed with right-of-way acquisition.
Federal
Electric Transmission Investment
In May 2011, FERC approved transmission rate incentives for the Illinois Rivers project, which is being developed by ATXI. In December 2011, MISO approved the Illinois Rivers project as well as the Spoon River and Mark Twain projects. The total investment in these three MISO-approved projects is expected to be more than $1.3 billion between 2013 to 2019. These projects are primarily located in Illinois and Missouri.
In February 2012, FERC approved ATXI's request for a forward-looking rate calculation with an annual revenue requirement reconciliation, as well as ATXI's request for implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project. In November 2012, FERC approved transmission rate incentives for the Spoon River project and the Mark Twain project. FERC also approved a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois' electric transmission business.
2011 Wholesale Distribution Rate Case
In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers by $11 million. These wholesale distribution revenues are treated as a deduction from Ameren Illinois' revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois has reached an agreement with four of its nine wholesale customers. The impasse with the remaining five wholesale customers has resulted in FERC litigation. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. A FERC decision is expected in 2013. Ameren has recorded $8 million in “Current regulatory liabilities” on its consolidated balance sheet as of December 31, 2012, for its estimate of the refund due to wholesale customers relating to billings from March 2011 through December 2012 based on the administrative law judge's initial decision.
Ameren Illinois Electric Transmission Rate Refund
On July 19, 2012, FERC issued an order approving Ameren Illinois' accounting for the Ameren Illinois Merger. As part of this order, FERC concluded that Ameren Illinois improperly included acquisition premiums, particularly goodwill, in determining its common equity used in its electric transmission formula rate, thereby inappropriately recovering a higher return on rate base from its electric transmission customers. The order required Ameren Illinois to make refunds to customers for such improperly included amounts. In August 2012, Ameren Illinois filed a request for rehearing of this order. It is unknown when FERC will rule on Ameren's rehearing request, as it is under no deadline to do so. After reviewing the FERC order and its calculation of the impact on electric transmission formula rates, Ameren Illinois concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund is warranted. If Ameren Illinois were to determine that a refund to its electric transmission customers is probable, a charge to earnings would be recorded for the refund in the period in which that determination was made and the amount could be estimated.
FERC Order - MISO Charges
Ameren Missouri and Ameren Illinois, as well as other MISO participants, have filed complaints with FERC with respect to the FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. Subsequently, FERC has issued a series of orders related to the applicability and the implementation of the order, which in some cases have conflicted with previous orders.
In May 2009, FERC changed the effective date for refunds such that certain operational costs would be allocated among MISO market participants beginning November 2008, instead of August 2007. In June 2009, Ameren Missouri and Ameren Illinois filed a request for rehearing. The rehearing request is pending.
In June 2009, FERC issued an order dismissing rehearing requests of a November 2008 order and waiving refunds of amounts billed that were included in the MISO charge, under the assumption that there was a rate mismatch for the period April 2006 through November 2007. Ameren Missouri and Ameren Illinois filed a request for rehearing in July 2009. This rehearing request is pending.
Ameren Missouri and Ameren Illinois do not believe that the ultimate resolution of these proceedings will have a material effect on their results of operations, financial position, or liquidity.
Ameren Missouri Power Purchase Agreement with Entergy
Beginning in 2005, FERC issued a series of orders addressing a complaint filed in 2001 by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates. The complaint alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing Ameren Missouri in 2007 for additional charges under a 165-megawatt power purchase agreement, and Ameren Missouri paid those charges. Additional charges continued during the remainder of the term of the power purchase agreement, which expired August 31, 2009. In May 2012, FERC issued an order upholding its January 2010 ruling that Entergy should not have included additional charges to Ameren Missouri under the power purchase agreement. Pursuant to the order, in June 2012, Entergy paid Ameren Missouri $31 million, with $24 million recorded as a reduction to “Purchased power” expense and $5 million for interest recorded as “Miscellaneous income” in the consolidated statement of income (loss), and the remaining $2 million recorded as an offset to the FAC under-recovered regulatory asset for the amount refundable to customers. The amount of the Entergy refund recorded to the FAC regulatory asset related to the period when the FAC was effective and, therefore, such costs were previously included in customer rates. As noted above, the MoPSC, in its December 2012 electric rate order, confirmed Ameren Missouri could retain the portion of the refund received from Entergy that related to the period prior to the implementation of the FAC. In July 2012, Entergy filed an appeal of FERC's January 2010 and May 2012 orders to the United States Court of Appeals for the District of Columbia. In December 2012, the Court of Appeals dismissed Entergy's appeal as premature because an Entergy motion seeking clarification or rehearing of the May 2012 order remains pending before FERC. It is unknown when FERC may act on the pending Entergy motion.
The LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy Services, Inc. to the United States Court of Appeals for the District of Columbia. In April 2008, that court ordered further FERC proceedings regarding LPSC’s complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the retroactive impact of these issues could have a financial impact on Ameren Missouri. Ameren Missouri is unable to predict how FERC will respond to the court’s decisions. Ameren Missouri estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. Ameren Missouri believes that the likelihood of incurring any expense is not probable, and therefore no liability has been recorded as of December 31, 2012.
Combined Construction and Operating License
In 2008, Ameren Missouri filed an application with the NRC for a COL for a new nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a new nuclear unit at its existing Missouri nuclear energy center site, and the NRC suspended review of the COL application.
In March 2012, the DOE announced the availability of investment funds for the design, engineering, manufacturing, and sale of American-made small modular nuclear reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the DOE's small modular nuclear reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. In November 2012, the DOE awarded investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that additional investment funds would be awarded during 2013. Westinghouse continues to pursue investment funds from the DOE.
If Westinghouse is awarded DOE's small modular reactor investment funds, Ameren Missouri will seek a COL from the NRC for a Westinghouse small modular reactor or multiple reactors at its Callaway energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear energy center at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC does not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it does preserve the option to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years.
Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal due to several factors, including the company's capitalized investments in new nuclear energy center development of $69 million as of December 31, 2012, the DOE investment funds that would help support the COL application, and Ameren Missouri's agreement with Westinghouse. If the DOE does not approve Westinghouse's application for the small modular reactor investment funds, Ameren Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse.
All of Ameren Missouri's costs incurred to license additional nuclear generation at the Callaway site will remain capitalized while management pursues options to maximize the value of its investment. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.
Pumped-storage Hydroelectric Energy Center Relicensing
In June 2008, Ameren Missouri filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric energy center for another 40 years. The existing FERC license expired on June 30, 2010. On July 2, 2010, Ameren Missouri received a license extension that allows Taum Sauk to continue operations until FERC issues a new license. FERC is reviewing the relicensing application. A FERC order is expected in 2013 or 2014. Ameren Missouri cannot predict the ultimate outcome of FERC's review of the application.
Regulatory Assets and Liabilities
In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, Ameren Missouri and Ameren Illinois defer certain costs pursuant to actions of regulators or based on the expected ability to recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts because of actions of regulators or because of the expectation that such amounts will be returned to customers in future rates. The following table presents Ameren’s regulatory assets and regulatory liabilities at December 31, 2012, and 2011:
 
 
2012
2011
Current regulatory assets:
 
 
 
 
 
Under-recovered FAC(a)(b)
 
$
145

 
$
83

 
Under-recovered Illinois electric power costs(a)(c)
 
—

 
4

 
Under-recovered PGA(a)(c)
 
12

 
8

 
MTM derivative losses(d)
 
90


120

 
Total current regulatory assets
 
$
247

 
$
215

 
Noncurrent regulatory assets:
 
 
 
 
 
Pension and postretirement benefit costs(e)
 
$
772

 
$
878

 
Income taxes(f)
 
235

 
239

 
Asset retirement obligations(g)
 
5

 
6

 
Callaway costs(a)(h)
 
44

 
48

 
Unamortized loss on reacquired debt(a)(i)
 
181

 
47

 
Recoverable costs - contaminated facilities(j)
 
248

 
102

 
MTM derivative losses(d)
 
135


100


SO2 emission allowances sale tracker(k)
 
2

 
6

 
Storm costs(l)
 
9

 
16

 
Demand-side costs(a)(m)
 
73

 
70

 
Reserve for workers’ compensation liabilities(n)
 
12

 
13

 
Credit facilities fees(o)
 
6

 
10

 
Employee separation costs(p)
 
2

 
6

 
Common stock issuance costs(q)
 
7

 
10

 
Construction accounting for pollution control equipment(a)(r)
 
23

 
25

 
Other(s)
 
32

 
27

 
Total noncurrent regulatory assets
 
$
1,786

 
$
1,603

 
Current regulatory liabilities:
 
 
 
 
 
Over-recovered FAC(t)
 
$
—

 
$
12

 
Over-recovered Illinois electric power costs(c)
 
58

 
64

 
Over-recovered PGA(c)
 
15

 
9

 
MTM derivative gains(u)
 
19


46


Wholesale distribution refund(v)
 
8

 
2

 
Total current regulatory liabilities
 
$
100

 
$
133

 
Noncurrent regulatory liabilities:
 
 
 
 
 
Income taxes(w)
 
$
46

 
$
48

 
Removal costs(x)
 
1,347

 
1,269

 
Asset retirement obligation(g)
 
80

 
29

 
MTM derivative gains(u)
 
2


82


Bad debt rider(y)
 
12

 
10

 
Pension and postretirement benefit costs tracker(z)
 
23

 
38

 
Energy efficiency rider(aa)
 
20

 
24

 
IEIMA revenue requirement reconciliation(ab)
 
55

 
—

 
Other(ac)
 
4

 
2

 
Total noncurrent regulatory liabilities
 
$
1,589

 
$
1,502

 

(a)
These assets earn a return.
(b)
Under-recovered fuel costs for periods from June 2010 through December 2012. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.
(c)
Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.
(d)
Deferral of commodity-related derivative MTM losses. The December 31, 2011 balance included the MTM losses on financial contracts entered into by Ameren Illinois with Marketing Company, which expired in December 2012.
(e)
These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 - Retirement Benefits for additional information.
(f)
Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 - Income Taxes for amortization period.
(g)
Recoverable or refundable removal costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations.
(h)
Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the energy center's current operating license which expires in 2024.
(i)
Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.
(j)
The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of actual expenditures. See Note 15 - Commitments and Contingencies for additional information.
(k)
A regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order. The MoPSC’s May 2010 electric rate order discontinued any future deferrals under this tracking mechanism. The MoPSC’s December 2012 rate order approved the amortization of these costs through December 2014.
(l)
Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. As approved by the December 2012 MoPSC electric rate order, the 2006, 2007, and 2008 storm costs are being amortized through December 2014. As approved by the May 2010 MoPSC electric rate order, the 2009 storm costs are being amortized through June 2015.
(m)
Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. Costs incurred from May 2008 through September 2008 are being amortized over a 10-year period that began in March 2009. Costs incurred from October 2008 through December 2009 are being amortized over a six-year period that began in July 2010. Costs incurred from January 2010 through February 2011 are being amortized over a six-year period that began in August 2011. Costs incurred from March 2011 through July 2012 are being amortized over a six-year period that began in January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case.
(n)
Reserve for workers’ compensation claims. The period of recovery will depend on the timing of actual expenditures.
(o)
Ameren Missouri’s costs incurred to enter into and maintain the 2012 Ameren Missouri Credit Agreement. These costs are being amortized over five years, beginning in November 2012. These costs are being amortized to construction work in progress, which will be subsequently depreciated when assets are placed into service.
(p)
Costs incurred for voluntary and involuntary separation programs. The 2009 Ameren Missouri-related costs are being amortized over two years, beginning in January 2013, as approved by the December 2012 MoPSC electric rate order. The 2009 Ameren Illinois-related costs are being amortized over three years, beginning in May 2010, as approved by the April 2010 ICC electric and natural gas rate order.
(q)
The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to recover its portion of Ameren’s September 2009 common stock issuance costs. These costs are being amortized over five years, beginning in July 2010.
(r)
The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was placed in customer rates. The amortization of these costs will be over the expected life of the Sioux energy center.
(s)
The Ameren Illinois total includes Ameren Illinois Merger integration and optimization costs, which are amortized over four years, beginning in January 2012. The Ameren Illinois total includes costs related to delivery service rate cases. The 2012 natural gas rate case costs are being amortized over a two-year period that began in January 2012. The electric rate case costs for the IEIMA initial rate filing are being amortized over a three-year period that began in January 2012. The Ameren Illinois total also includes a portion of the unamortized debt fair value adjustment recorded upon Ameren's acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007. At Ameren Missouri, the balance primarily includes cost associated with the retirement of renewable energy credits and solar rebates to fulfill its renewable energy portfolio requirement. Costs incurred from January 2010 through July 2012 are being amortized over three years, beginning January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case.
(t)
Over-recovered fuel costs from March 2009 through September 2009 as ordered by the MoPSC in April 2011. Customer refunds concluded in 2012. Specific accumulation periods aggregate the over-recovered costs over four months, any related adjustments occur over the following four months, and then recovery from customers occurs over the next eight months.
(u)
Deferral of commodity-related derivative MTM gains.
(v)
Estimated refund to wholesale electric customers. See 2011 Wholesale Distribution Rate Case above.
(w)
Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 - Income Taxes for amortization period.
(x)
Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations.
(y)
A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by Ameren Illinois under GAAP and the level of such costs included in electric and natural gas rates. The over-recovery relating to 2010 was refunded to customers from June 2011 through May 2012. The over-recovery relating to 2011 is being refunded to customers from June 2012 through May 2013. The over-recovery relating to 2012 will be refunded to customers from June 2013 through May 2014.
(z)
A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs built into rates. For periods prior to August 2012, the MoPSC's December 2012 electric rate order directed the amortization to occur over five years, beginning in January 2013. For periods after August 2012, the amortization period will be determined in a future Ameren Missouri electric rate case.
(aa)
A regulatory tracking mechanism that allows Ameren Illinois to recover its electric and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. This over-recovery will be refunded to customers over the following 12 months after the plan year.
(ab)
The difference between Ameren Illinois' 2012 revenue requirement calculated under the IEIMA's performance-based formula ratemaking framework, and the revenue requirement included in customer rates for 2012. Subject to ICC approval, this liability will be refunded to customers in 2014.
(ac)
Balance primarily includes an Ameren Missouri liability relating to its 2010 property tax refund. The MoPSC's December 2012 electric rate order directed a refund to customers over a two-year period, beginning in January 2013.
Ameren Missouri and Ameren Illinois continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are charged to earnings when it is no longer probable that such amounts will be recovered through future revenues. To the extent that payments of regulatory liabilities are no longer probable, the amounts are credited to earnings.
Property And Plant, Net
PROPERTY AND PLANT, NET
PROPERTY AND PLANT, NET
The following table presents Ameren's property and plant, net, at December 31, 2012, and 2011:
 
Ameren(a)
2012
 
Property and plant, at original cost:
 
Electric
$
20,942

Natural gas
1,854

 
22,796

Less: Accumulated depreciation and amortization
8,346

 
14,450

Construction work in progress:
 
Nuclear fuel in process
317

Other
581

Property and plant, net
$
15,348

2011
 
Property and plant, at original cost:
 
Electric
$
20,098

Natural gas
1,751

 
21,849

Less: Accumulated depreciation and amortization
7,868

 
13,981

Construction work in progress:
 
Nuclear fuel in process
255

Other
612

Property and plant, net
$
14,848


(a)
Amounts include two electric generation CTs under two separate capital lease agreements. The gross asset value of those agreements was $228 million and $229 million at December 31, 2012, and 2011, respectively. The total accumulated depreciation associated with the two CTs was $52 million and $52 million at December 31, 2012, and 2011, respectively. In addition, Ameren has investments in debt securities, which are classified as held-to-maturity, related to the two CTs from the city of Bowling Green and Audrain County. As of December 31, 2012, and 2011, the carrying value of these debt securities was $304 million and $309 million, respectively.
The following table provides accrued capital expenditures at December 31, 2012, 2011, and 2010, which represent noncash investing activity excluded from the statements of cash flows:
2012
$
103

2011
92

2010
70

Short-Term Debt And Liquidity
SHORT-TERM DEBT AND LIQUIDITY
SHORT-TERM DEBT AND LIQUIDITY
The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, and drawings under committed bank credit agreements, or commercial paper issuances.
2012 Credit Agreements
On November 14, 2012, Ameren entered into the $1 billion 2012 Missouri Credit Agreement. The 2010 Missouri Credit Agreement was terminated when the 2012 Missouri Credit Agreement when into effect. Also on November 14, 2012, Ameren entered into the $1.1 billion 2012 Illinois Credit Agreement. The 2010 Illinois Credit Agreement was terminated when the 2012 Illinois Credit Agreement went into effect. These facilities cumulatively provide $2.1 billion of credit through November 14, 2017, which date is inclusive of the Ameren Missouri and Ameren Illinois borrowing sublimit extensions discussed below of the maturity date to November 14, 2017, and which may be extended with the agreement of the lenders, subject to the terms of such agreements, for two additional one-year periods. The facilities currently include 24 international, national, and regional lenders, with no lender providing more than $125 million of credit in aggregate.
In addition, the 2010 Genco Credit Agreement, under which Ameren was a borrower, was not renewed and was terminated contemporaneously with the effectiveness of the 2012 Credit Agreements.
The obligations of each borrower under the respective 2012 Credit Agreements to which it is a party are several and not joint, and, except under limited circumstances relating to expenses and indemnities, the obligations of Ameren Missouri and Ameren Illinois under the respective 2012 Credit Agreements are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum aggregate amount available to each borrower under each facility is shown in the following table (such amount being such borrower's "Borrowing Sublimit"):
 
2012 Missouri Credit Agreement
2012 Illinois
Credit Agreement
Ameren
$
500

$
300

Ameren Missouri
800

(a)

Ameren Illinois
(a)

$
800


(a)
Not applicable.
Ameren has the option to seek additional commitments from existing or new lenders to increase the total facility size of the 2012 Credit Agreements up to the following maximum amounts: 2012 Missouri Credit Agreement - $1.2 billion; and 2012 Illinois Credit Agreement - $1.3 billion. Each of the 2012 Credit Agreements will mature and expire with respect to Ameren on November 14, 2017, unless extended as described above. Borrowing Sublimits of Ameren Missouri and Ameren Illinois under the applicable 2012 Credit Agreements will mature and expire on November 13, 2013, subject to extension thereof on a 364-day basis, as requested by the borrower and approved by the lenders, or for a longer period upon receipt of any and all required federal or state regulatory approvals, as permitted under the 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement, but in no event later than November 14, 2017. Ameren Missouri and Ameren Illinois intend to seek regulatory approval to extend the maturity dates of their respective Borrowing Sublimit under the 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement to November 14, 2017. If and when such regulatory approvals are received, no lender approval will be required to effect the extensions. The principal amount of each revolving loan owed by a borrower under any of the 2012 Credit Agreements to which it is a party will be due and payable no later than the final maturity date relating to such borrower under such 2012 Credit Agreements.
The obligations of all borrowers under the 2012 Credit Agreements are unsecured. Loans are available on a revolving basis under each of the 2012 Credit Agreements and may be repaid and, subject to satisfaction of the conditions to borrowing, reborrowed from time to time. At the election of each borrower, the interest rates on such loans will be the alternate base rate ("ABR") plus the margin applicable to the particular borrower and/or the Eurodollar rate plus the margin applicable to the particular borrower. The applicable margins will be determined by the borrower's long-term unsecured credit ratings or, if no such ratings are then in effect, the borrower's corporate/issuer ratings then in effect. Letters of credit in an aggregate undrawn face amount not to exceed 25% of the applicable aggregate commitment under the respective 2012 Credit Agreements are also available for issuance for the account of the borrowers thereunder (but within the $2.1 billion overall combined facility borrowing limitations of the 2012 Credit Agreements).
The borrowers will use the proceeds from any borrowings under the 2012 Credit Agreements for general corporate purposes, including working capital, commercial paper liquidity support, loan funding under the Ameren money pool arrangements or other short-term intercompany loan arrangements, or paying fees and expenses incurred in connection with the 2012 Credit Agreements.
The 2012 Credit Agreements are used to borrow cash, to issue letters of credit, and to support issuances under Ameren's commercial paper programs. Any of the 2012 Credit Agreements are available to Ameren to support borrowings under Ameren's commercial paper program, subject to borrowing sublimits. The 2012 Missouri Credit Agreement is available to support issuances under Ameren Missouri's commercial paper program, and the 2012 Illinois Credit Agreement is available to support issuances under Ameren Illinois' commercial paper program. As of December 31, 2012, based on letters of credit issued under the 2012 Credit Agreements, the aggregate amount of credit capacity available to Ameren (parent) at December 31, 2012, was $2.09 billion.
The following table summarizes the borrowing activity and relevant interest rates under the 2010 Missouri Credit Agreement, which terminated on November 14, 2012, for the years ended December 31, 2012, and 2011 and excludes issued letters of credit. Ameren, Ameren Missouri and Ameren Illinois did not borrow under the 2012 Credit Agreements from November 14, 2012, through December 31, 2012.
2010 Missouri Credit Agreement ($800 million) (Terminated)
Ameren
(Parent)
 
Ameren
Missouri
 
Total
2012
 
 
 
 
 
Average daily borrowings outstanding during 2012(a)
$
—

 
$
1

 
$
1

Outstanding credit facility borrowings at period end
—

 
—

 
—

Weighted-average interest rate during 2012(a)
—
%
 
4.15
%
 
4.15
%
Peak credit facility borrowings during 2012(a)
$
—

 
$
50

 
$
50

Peak interest rate during 2012
—
%
 
4.15
%
 
4.15
%
2011
 
 
 
 
 
Average daily borrowings outstanding during 2011
$
105

 
$
—

 
$
105

Outstanding credit facility borrowings at period end
—

 
—

 
—

Weighted-average interest rate during 2011
2.30
%
 
—

 
2.30
%
Peak credit facility borrowings during 2011
$
340

 
$
—

 
$
340

Peak interest rate during 2011
4.30
%
 
—

 
4.30
%
(a)
Calculated through termination date.
Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the years ended December 31, 2012, and 2011, respectively.
Commercial Paper
At December 31, 2012, Ameren did not have any commercial paper outstanding. At December 31, 2011, Ameren had $148 million of commercial paper outstanding. During the years ended December 31, 2012, and 2011, Ameren had average daily commercial paper balances outstanding of $49 million and $311 million with a weighted-average interest rate of 0.92% and 0.87%, respectively. The peak amounts of short-term commercial paper outstanding during the years ended December 31, 2012, and 2011, were $229 million and $435 million, respectively. The peak interest rate during the years ended December 31, 2012, and 2011, was 1.25% and 1.46%, respectively.
Indebtedness Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants.    
The 2012 Credit Agreements contain conditions to borrowings and issuances of letters of credit similar to those contained in the 2010 Credit Agreements, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation, and the absence of any notice of any violation, liability or requirement under any environmental laws that could have a material adverse effect), and obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2012 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation.
The 2012 Credit Agreements also contain nonfinancial covenants similar to those contained in the 2010 Credit Agreements, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The 2012 Credit Agreements requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of December 31, 2012, the ratio of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, was 51% for Ameren. In addition, under the 2012 Illinois Credit Agreement and, by virtue of the cross-default provisions of the 2012 Missouri Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1.0, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2012 Illinois Credit Agreement. Ameren’s ratio as of December 31, 2012 was 5.0 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement.
The 2012 Credit Agreements contain default provisions. The default provisions in the 2012 Credit Agreements apply separately to each borrower, provided, however, that a default of Ameren Missouri or Ameren Illinois under the applicable 2012 Credit Agreement will also be deemed to constitute a default of Ameren under such agreement. Defaults include a cross-default to a default of such borrower under any other agreement covering outstanding indebtedness of such borrower and certain subsidiaries (other than project finance subsidiaries and nonmaterial subsidiaries) in excess of $50 million in the aggregate (including under the other 2012 Credit Agreement). However, under the default provisions of the 2012 Credit Agreements, any default of Ameren under any such 2012 Credit Agreements that results solely from a default of Ameren Missouri or Ameren Illinois thereunder does not result in a cross-default of Ameren under the other 2012 Credit Agreement. Further, the 2012 Credit Agreement default provisions provide that an Ameren default under any of the 2012 Credit Agreements does not trigger a default by Ameren Missouri or Ameren Illinois.
None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit agreements at December 31, 2012.
Money Pools
Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.
Utility
Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren may participate in the utility money pool only as a lender. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2012 Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2012, was 0.13%. There were no utility money pool borrowings during the year ended December 31, 2011.
Non-state-regulated Subsidiaries
Ameren (parent), and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the 2012 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. AER, Genco, AERG and Marketing Company may participate in the non-state-regulated money pool through the closing of the divestiture transaction as detailed in Note 16 - Divestiture Transactions and Discontinued Operations. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2012, was 0.61% (2011 - 0.77%).
Unilateral Borrowing Agreement
In addition, a unilateral borrowing agreement exists among Ameren, Ameren Illinois, and Ameren Services, which enables Ameren Illinois to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by Ameren Illinois under the unilateral borrowing agreement and the utility money pool agreement, together with any outstanding Ameren Illinois external credit facility borrowings or commercial paper issuances, may not exceed $500 million, pursuant to authorization from the ICC. Ameren Illinois is not currently borrowing under the unilateral borrowing agreement. Ameren Services is responsible for the operation and administration of the unilateral borrowing agreement.
Long-Term Debt And Equity Financings
LONG-TERM DEBT AND EQUITY FINANCINGS
LONG-TERM DEBT AND EQUITY FINANCINGS
The following table presents Ameren's long-term debt outstanding, including maturities due within one year, as of December 31, 2012, and 2011:
 
2012
 
2011
Ameren (Parent):
 
 
 
8.875% Senior unsecured notes due 2014
$
425

 
$
425

Less: Unamortized discount and premium
(1
)
 
(1
)
Long-term debt, net
$
424

 
$
424

Ameren Missouri:
 
 
 
Senior secured notes:(a)
 
 
 
5.25% Senior secured notes due 2012
$
—

 
$
173

4.65% Senior secured notes due 2013
200

 
200

5.50% Senior secured notes due 2014
104

 
104

4.75% Senior secured notes due 2015
114

 
114

5.40% Senior secured notes due 2016
260

 
260

6.40% Senior secured notes due 2017
425

 
425

6.00% Senior secured notes due 2018(b)
179

 
250

5.10% Senior secured notes due 2018
199

 
200

6.70% Senior secured notes due 2019(b)
329

 
450

5.10% Senior secured notes due 2019
244

 
300

5.00% Senior secured notes due 2020
85

 
85

5.50% Senior secured notes due 2034
184

 
184

5.30% Senior secured notes due 2037
300

 
300

8.45% Senior secured notes due 2039(b)
350

 
350

3.90% Senior secured notes due 2042(b)
485

 
—

Environmental improvement and pollution control revenue bonds:
 
 
 
1992 Series due 2022(c)(d)
47

 
47

1993 5.45% Series due 2028(e)
44

 
44

1998 Series A due 2033(c)(d)
60

 
60

1998 Series B due 2033(c)(d)
50

 
50

1998 Series C due 2033(c)(d)
50

 
50

Capital lease obligations:
 
 
 
City of Bowling Green capital lease (Peno Creek CT) through 2022
64

 
69

Audrain County capital lease (Audrain County CT) due 2023
240

 
240

Total long-term debt, gross
4,013

 
3,955

Less: Unamortized discount and premium
(7
)
 
(5
)
Less: Maturities due within one year
(205
)
 
(178
)
Long-term debt, net
$
3,801

 
$
3,772

 
2012
 
2011
Ameren Illinois:
 
 
 
Senior secured notes:
 
 
 
8.875% Senior secured notes due 2013(f)(h)
$
150

 
$
150

6.20% Senior secured notes due 2016(f)
54

 
54

6.25% Senior secured notes due 2016(g)
75

 
75

6.125% Senior secured notes due 2017(g)(i)
250

 
250

6.25% Senior secured notes due 2018(g)(i)
144

 
337

9.75% Senior secured notes due 2018(g)(i)
313

 
400

2.70% Senior secured notes due 2022(g)(i)
400

 
—

6.125% Senior secured notes due 2028(g)
60

 
60

6.70% Senior secured notes due 2036(g)
61

 
61

6.70% Senior secured notes due 2036(f)
42

 
42

Environmental improvement and pollution control revenue bonds:
 
 
 
6.20% Series 1992B due 2012
—

 
1

2000 Series A 5.50% due 2014
—

 
51

5.90% Series 1993 due 2023(j)
32

 
32

5.70% 1994A Series due 2024(k)
36

 
36

1993 Series C-1 5.95% due 2026(l)
35

 
35

1993 Series C-2 5.70% due 2026(l)
8

 
8

1993 Series B-1 due 2028(d)(l)
17

 
17

5.40% 1998A Series due 2028(k)
19

 
19

5.40% 1998B Series due 2028(k)
33

 
33

Fair-market value adjustments
4

 
5

Total long-term debt, gross
1,733

 
1,666

Less: Unamortized discount and premium
(6
)
 
(8
)
Less: Maturities due within one year
(150
)
 
(1
)
Long-term debt, net
$
1,577

 
$
1,657

Ameren consolidated long-term debt, net
$
5,802

 
$
5,853

(a)
These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042.
(b)
Ameren Missouri has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its first mortgage bonds. Ameren Missouri has also agreed to prevent a first mortgage bond release date from occurring as long as any of the 8.45% senior secured notes due 2039 and any of the 3.90% senior secured notes due 2042 remain outstanding.
(c)
These bonds are secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri's senior secured notes. The bonds are also backed by an insurance guarantee policy.
(d)
Interest rates, and periods during which such rates apply, vary depending on our selection of defined rate modes. Maximum interest rates could range up to 18% depending on the series of bonds. The average interest rates for 2012 and 2011 were as follows:
 
2012
 
2011
Ameren Missouri 1992 Series
0.30
%
 
0.34
%
Ameren Missouri 1998 Series A
0.65
%
 
0.69
%
Ameren Missouri 1998 Series B
0.64
%
 
0.68
%
Ameren Missouri 1998 Series C
0.64
%
 
0.69
%
Ameren Illinois 1993 Series B-1
0.22
%
 
0.28
%

(e)
These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and are secured by substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value.
(f)
These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the CILCO first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2023.
(g)
These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028.
(h)
Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its CILCO first mortgage bonds, and therefore a CILCO first mortgage bond release date will not occur while any of such notes are outstanding.
(i)
Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its Ameren Illinois mortgage bonds, and therefore an Ameren Illinois first mortgage bond release date will not occur as long as any of these notes are outstanding.
(j)
These bonds are first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture and are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value.
(k)
These bonds are mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture and are secured by substantially all property of the former IP and CIPS. The bonds are callable at 100% of par value. The bonds are also backed by an insurance guarantee policy.
(l)
The bonds are callable at 100% of par value.
The following table presents Ameren's aggregate maturities of long-term debt, including current maturities, at December 31, 2012:
 
 Ameren
(Parent)(a)
 
 Ameren
Missouri(a)
 
 Ameren
Illinois(a)(b)
 
Ameren
Consolidated
2013
$
—

 
$
205

 
$
150

 
$
355

2014
425

 
109

 
—

 
534

2015
—

 
120

 
—

 
120

2016
—

 
266

 
129

 
395

2017
—

 
431

 
250

 
681

Thereafter
—

 
2,882

 
1,200

 
4,082

Total
$
425

 
$
4,013

 
$
1,729

 
$
6,167

(a)
Excludes unamortized discount and premium of $1 million, $7 million, and $6 million at Ameren (Parent), Ameren Missouri, and Ameren Illinois, respectively.
(b)
Excludes $4 million related to Ameren Illinois’ long-term debt fair-market value adjustments, which are being amortized to interest expense over the remaining life of the debt.
All classes of Ameren Missouri’s and Ameren Illinois’ preferred stock are entitled to cumulative dividends and have voting rights. Preferred stock not subject to mandatory redemption of Ameren's subsidiaries was included in "Noncontrolling Interests" on Ameren's consolidated balance sheet. The following table presents the outstanding preferred stock of Ameren Missouri and Ameren Illinois that is not subject to mandatory redemption. The preferred stock is redeemable, at the option of the issuer, at the prices shown below as of December 31, 2012, and 2011:
 
 
 
Redemption Price(per share)
 
2012
 
2011
Ameren Missouri:
 
 
 
 
 
 
 
Without par value and stated value of $100 per share, 25 million shares authorized
 
 
 
 
 
 
$3.50 Series
130,000 shares
 
$
110.00

 
$
13

 
$
13

$3.70 Series
40,000 shares
 
104.75

 
4

 
4

$4.00 Series
150,000 shares
 
105.625

 
15

 
15

$4.30 Series
40,000 shares
 
105.00

 
4

 
4

$4.50 Series
213,595 shares
 
110.00

(a) 
21

 
21

$4.56 Series
200,000 shares
 
102.47

 
20

 
20

$4.75 Series
20,000 shares
 
102.176

 
2

 
2

$5.50 Series A
14,000 shares
 
110.00

 
1

 
1

Total
 
 
 
$
80

 
$
80

Ameren Illinois:
 
 
 
 
 
 
 
With par value of $100 per share, 2 million shares authorized
 
 
 
 
 
 
4.00% Series
144,275 shares
 
$
101.00

 
$
14

 
$
14

4.08% Series
45,224 shares
 
103.00

 
5

 
5

4.20% Series
23,655 shares
 
104.00

 
2

 
2

4.25% Series
50,000 shares
 
102.00

 
5

 
5

4.26% Series
16,621 shares
 
103.00

 
2

 
2

4.42% Series
16,190 shares
 
103.00

 
2

 
2

4.70% Series
18,429 shares
 
103.00

 
2

 
2

4.90% Series
73,825 shares
 
102.00

 
7

 
7

4.92% Series
49,289 shares
 
103.50

 
5

 
5

5.16% Series
50,000 shares
 
102.00

 
5

 
5

6.625% Series
124,273.75 shares
 
100.00

 
12

 
12

7.75% Series
4,542 shares
 
100.00

 
1

 
1

Total
 
 
 
$
62

 
$
62

Total Ameren(b)
 
 
 
$
142

 
$
142

(a)
In the event of voluntary liquidation, $105.50.
(b)
Preferred stock not subject to mandatory redemption of Ameren's subsidiaries was included in "Noncontrolling Interests" on Ameren's consolidated balance sheet.
Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding.
Ameren
Ameren filed a Form S-3 registration statement with the SEC in June 2011, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, treasury shares, or shares purchased in the open market or in privately negotiated transactions. In 2012, Ameren shares were purchased in the open market for DRPlus and its 401(k) plan. Under DRPlus and its 401(k) plan, Ameren issued 2.2 million and 3.0 million shares of common stock in 2011 and 2010, respectively, which were valued at $65 million and $80 million for the respective years.
Ameren Missouri
On September 11, 2012, Ameren Missouri issued $485 million principal amount of 3.90% senior secured notes due September 15, 2042, with interest payable semiannually on March 15 and September 15 of each year, beginning March 15, 2013. These notes are secured by first mortgage bonds. Ameren Missouri received net proceeds of $478 million. The proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Missouri's tender offer on September 20, 2012, including the payment of interest and all related fees and expenses, and to retire the $173 million principal amount 5.25% senior secured notes that matured in September 2012.
On September 20, 2012, Ameren Missouri completed its tender offer to purchase for cash its outstanding 6.00% senior secured notes due 2018, 6.70% senior secured notes due 2019, 5.10% senior secured notes due 2018, and 5.10% senior secured notes due 2019. Any notes that were not tendered and purchased in the tender offer remain outstanding and continue to be obligations of Ameren Missouri. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:
Senior Secured Notes
Principal Amount Repurchased
 
Premium Plus Accrued
and Unpaid Interest(a)
 
Principal Amount Outstanding After Tender Offer
6.00% senior secured notes due 2018
$
71

 
$
19

 
$
179

6.70% senior secured notes due 2019
121

 
35

 
329

5.10% senior secured notes due 2018
1

 
(b)

 
199

5.10% senior secured notes due 2019
56

 
12

 
244

(a)
The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $485 million 3.90% senior secured notes due 2042.
(b)
Amount is less than $1 million.
Ameren Illinois
On August 20, 2012, Ameren Illinois issued $400 million principal amount of 2.70% senior secured notes due September 1, 2022, with interest payable semiannually on March 1 and September 1 of each year, beginning March 1, 2013. These notes are secured by first mortgage bonds. Ameren Illinois received net proceeds of $397 million. The proceeds were used, together with other available cash, to provide the funds necessary to complete Ameren Illinois' tender offer on August 27, 2012, including the payment of interest and all related fees and expenses, and to redeem all $51 million principal amount of 5.50% pollution control revenue bonds at par value plus accrued interest.
On August 27, 2012, Ameren Illinois completed its tender offer to purchase for cash its outstanding 9.75% senior secured notes due 2018 and 6.25% senior secured notes due 2018. Any notes that were not tendered and purchased in the tender offer remain outstanding and continue to be obligations of Ameren Illinois. The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:
Senior Secured Notes
Principal Amount Repurchased
 
Premium Plus Accrued
and Unpaid Interest(a)
 
Principal Amount Outstanding After Tender Offer
9.75% senior secured notes due 2018
$
87

 
$
36

 
$
313

6.25% senior secured notes due 2018
194

 
47

 
144

(a)
The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $400 million 2.70% senior secured notes due 2022.
In November 2012, $1 million of Ameren Illinois' 6.20% Series 1992B Pollution Control revenue bonds matured and were retired.
Indenture Provisions and Other Covenants
Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable as of December 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.
 
Required Interest
Coverage Ratio(a)
Actual Interest
Coverage Ratio
Bonds Issuable(b)
 
Required Dividend
Coverage Ratio(c)
Actual Dividend
Coverage Ratio
Preferred Stock
Issuable
Ameren Missouri
          >2.0
4.6

$
4,056

  
>2.5
122.8

$
2,351

Ameren Illinois
          >2.0
7.1

3,439

(d) 
>1.5
2.8

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.
Ameren’s indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2012 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.
Ameren Missouri and Ameren Illinois and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds “properly included in capital account.” The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.
Ameren Illinois’ articles of incorporation require dividend payments on its common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization after the Ameren Illinois Merger and AERG distribution. As of December 31, 2012, Ameren Illinois’ ratio of common stock equity to total capitalization was 57%.
In order for the Ameren Companies to issue securities in the future, they will have to comply with all applicable requirements in effect at the time of any such issuances.
Off-Balance-Sheet Arrangements
At December 31, 2012, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future. See Note 14 - Related Party Transactions with New AER for Ameren (parent) guarantees on behalf of its subsidiaries.
Other Income And Expenses
OTHER INCOME AND EXPENSES
OTHER INCOME AND EXPENSES
The following table presents the components of "Other Income and Expenses" in Ameren's consolidated statement of income (loss) for the years ended December 31, 2012, 2011, and 2010:
 
2012
 
2011
 
2010
Ameren:
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
Interest and dividend income
$
4

(a) 
$
3

 
$
4

Interest income on industrial development revenue bonds
28

 
28

 
28

Allowance for equity funds used during construction
36

 
34

 
52

Other
2

 
3

 
4

Total miscellaneous income
$
70

 
$
68

 
$
88

Miscellaneous expense:
 
 
 
 
 
Donations
$
24

(b) 
$
8

 
$
19

Other
13

 
15

 
13

Total miscellaneous expense
$
37

 
$
23

 
$
32

(a)
Includes interest income relating to a 2012 refund of charges included in an expired power purchase agreement with Entergy. See Note 2 - Rate and Regulatory Matters for additional information.
(b)
Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' 2012 participation in the formula ratemaking process.
Derivative Financial Instruments
DERIVATIVE FINANCIAL INSTRUMENTS
DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, electricity, and uranium. Such price fluctuations may cause the following:
•
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•
market values of coal, natural gas and uranium inventories that differ from the cost of those commodities in inventory; and
•
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.


The following table presents open gross commodity contract volumes by commodity type as of December 31, 2012, and 2011:
  
Quantity (in millions, except as indicated)
Commodity
Accrual & NPNS
Contracts(a)
 
Other
Derivatives(b)
 
Derivatives That Qualify for
Regulatory Deferral(c)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Coal (in tons)
96

 
116

 
(d)

 
(d)

 
(d)

 
(d)

Fuel oils (in gallons)(e)
(d)

 
(d)

 
(d)

 
(d)

 
70

 
53

Natural gas (in mmbtu)
20

 
50

 
—

 
9

 
147

 
193

Power (in megawatthours)
24

 
12

 
2

 
1

 
23

 
21

Renewable energy credits(f)
15

 
16

 
(d)

 
(d)

 
(d)

 
(d)

Uranium (pounds in thousands)
5,142

 
5,553

 
(d)

 
(d)

 
446

 
148

(a)
Accrual contracts include commodity contracts that do not qualify as derivatives. As of December 31, 2012, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.
(b)
As of December 31, 2012, these contracts ran through December 2014 for power.
(c)
As of December 31, 2012, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively.
(d)
Not applicable.
(e)
Fuel oils consist of heating and crude oil.
(f)
A renewable energy credit is created for every megawatthour of renewable energy generated. Ameren contracts include renewable energy credits from solar and wind-generated power.
Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 8 - Fair Value Measurements for discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the consolidated statement of income (loss) in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the consolidated statement of income (loss).
Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and Ameren Illinois believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.
Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for, or we do not choose to elect, the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the consolidated statement of income (loss) in the period in which the change occurs.
Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible commodity contracts.
The following table presents the carrying value and balance sheet location of all derivative instruments as of December 31, 2012, and 2011:
 
Balance Sheet Location
 
2012
 
2011
Derivative assets not designated as hedging instruments(a)
 
 
 
 
Commodity contracts:
 
 
 
 
Fuel oils
Other current assets
 
$
8

 
$
17

 
Other assets
 
4

 
6

Natural gas
Other current assets
 
1

 
3

 
Other assets
 
1

 
1

Power
Other current assets
 
14

 
30

 
Other assets
 
1

 
77

 
Total assets
 
$
29

 
$
134

Derivative liabilities not designated as hedging instruments(a)
 
 
 
 
Commodity contracts:
 
 
 
 
 
Fuel oils
MTM derivative liabilities
 
$
2

 
$
1

 
Other deferred credits and liabilities
 
2

 
—

Natural gas
MTM derivative liabilities
 
64

 
103

 
Other deferred credits and liabilities
 
45

 
92

Power
MTM derivative liabilities
 
25

 
18

 
Other deferred credits and liabilities
 
90

 
8

Uranium
MTM derivative liabilities
 
1

 
—

 
Other deferred credits and liabilities
 
1

 
1

 
Total liabilities
 
$
230

 
$
223

(a)
Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred in regulatory assets or regulatory liabilities as of December 31, 2012, and 2011:
 
 
2012
 
2011
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
Fuel oils derivative contracts(a)
 
$
4

 
$
19

Natural gas derivative contracts(b)
 
(107
)
 
(191
)
Power derivative contracts(c)
 
(99
)
 
81

Uranium derivative contracts(d)
 
(2
)
 
(1
)


(a)
Represents net gains on fuel oils derivative contracts. These contracts are a partial hedge of transportation costs for coal through October 2015 as of December 31, 2012. Current gains deferred as regulatory liabilities include $4 million as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012.
(b)
Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2017 as of December 31, 2012. Current gains deferred as regulatory liabilities include $1 million as of December 31, 2012. Current losses deferred as regulatory assets include $64 million as of December 31, 2012.
(c)
Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 as of December 31, 2012. Current gains deferred as regulatory liabilities include $14 million as of December 31, 2012. Current losses deferred as regulatory assets include $24 million as of December 31, 2012.
(d)
Represents net losses on uranium derivative contracts. These contracts are a partial hedge of uranium requirements through September 2014 as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012, respectively.
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.
We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master trading and netting agreement level by counterparty.
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. The following table presents by groupings the maximum exposure, as of December 31, 2012, and 2011, if counterparty groups were to fail completely to perform on contracts. The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.
 
Affiliates
 
Coal
Producers
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Total
2012
$
—

 
$
—

 
$
2

 
$
3

 
$
15

 
$
3

 
$
23

2011
$
1

 
$
35

 
$
85

 
$
4

 
$
27

 
$
4

 
$
156

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The Ameren Companies held no cash from counterparties based on contractual rights under agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements as of December 31, 2012, and 2011. Other collateral used to reduce exposure consisted of letters of credit in the amount of $1 million and $1 million held at December 31, 2012, and 2011, respectively. The following table presents the potential loss after consideration of the application of master trading and netting agreements and collateral held as of December 31, 2012, and 2011:
 
Affiliates
 
Coal
Producers
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Total
2012
$
—

 
$
—

 
$
1

 
$
1

 
$
10

 
$
3

 
$
15

2011
$
1

 
$
35

 
$
85

 
$
3

 
$
22

 
$
4

 
$
150

Derivative Instruments with Credit Risk-Related Contingent Features
Our commodity contracts contain collateral provisions tied to the Ameren Companies’ credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of December 31, 2012, and 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on December 31, 2012, or 2011, respectively, and (2) those counterparties with rights to do so requested collateral:
 
Aggregate Fair Value of
Derivative Liabilities(a)
 
Cash
Collateral Posted
 
Potential Aggregate Amount of
Additional Collateral Required(b)
2012
$
226

 
$
61

 
$
155

2011
$
322

 
$
104

 
$
211

(a)
Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures.
(b)
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.
Other Derivatives
The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the years ended December 31, 2012, and 2011:
 
 
Location of Gain (Loss)
Recognized in Income
 
Gain (Loss) Recognized
in Income
 
2012
 
2011
Natural gas (generation)
 
Operating Expenses - Fuel
 
$
—

 
$
(1
)

Derivatives Subject to Regulatory Deferral
The following table represents the net change in market value associated with derivatives that qualify for regulatory deferral for the years ended December 31, 2012, and 2011:
  
 
Gain (Loss) Recognized
In Regulatory Liabilities
or Regulatory Assets
2012
 
2011
Fuel oils
 
$
(15
)
 
$
—

Natural gas
 
84

 
(26
)
Power
 
(180
)
 
80

Uranium
 
(1
)
 
(3
)
Total
 
$
(112
)
 
$
51

Fair Value Measurements
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri’s nuclear decommissioning trust fund.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri's nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index comprises stocks of large capitalization companies.
Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including corporate bonds and other fixed-income securities, United States treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.
Fixed income securities are valued using prices from independent industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the nuclear decommissioning trust fund are primarily corporate bonds, asset-backed securities and United States agency bonds.
Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivatives contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.
Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors. Note 17 - Impairment and Other Charges describes Ameren's use of significant unobservable inputs, which are Level 3 inputs, to estimate the fair value of Merchant Generation's long-lived assets.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:
 
Fair Value
 
 
Range [Weighted
 
Assets
Liabilities
Valuation Technique(s)
Unobservable Input
 Average]
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
Fuel oils
$
8

$
(3
)
Discounted cash flow
Escalation rate(%)(b)
.21 - .60 [.44]
 
 
 
 
Counterparty credit risk(%)(c)(d)
.12 - 1 [1]
 
 
 
 
Ameren credit risk(%)(c)(d)
2
 
 
 
Option model
Volatilities(%)(b)
7 - 27 [24]
Power(e)
14

(114
)
Discounted cash flow
Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)
22 - 47 [31]
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(281) - 1,851 [178]
 
 
 
 
Nodal basis($/MWh)(c)
(5) - (1) [(3)]
 
 
 
 
Counterparty credit risk(%)(c)(d)
.22 - 1 [1]
 
 
 
 
Ameren credit risk(%)(c)(d)
2 - 5 [5]
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 8 [6]
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7 [6]
Uranium
—

(2
)
Discounted cash flow
Average bid/ask consensus pricing($/pound)(b)
43 - 46 [44]
(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 credit risk is only applied to counterparties with derivative liability balances.
(e)
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.
In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. We recorded no gains or losses related to valuation adjustments for counterparty default risk in 2012, 2011, or 2010. The counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million and $4 million, as of December 31, 2012, and 2011, respectively.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
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
 
$
269

 
$
144

 
$
22

 
$
435

Liabilities:
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
1

 
—

 
3

 
4

 
Natural gas
 
7

 
102

 
—

 
109

 
Power
 
—

 
1

 
114

 
115

 
Uranium
 
—

 
—

 
2

 
2

 
Total
 
$
8

 
$
103

 
$
119

 
$
230

(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.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2011:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
20

 
$
—

 
$
3

 
$
23

 
Natural gas
 
2

 
—

 
2

 
4

 
Power
 
—

 
1

 
106

 
107

 
Total derivative assets - commodity contracts
 
$
22

 
$
1

 
$
111

 
$
134

 
Nuclear decommissioning trust fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
3

 
—

 
—

 
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
234

 
—

 
—

 
234

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
44

 
—

 
44

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
65

 
—

 
65

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
237

 
$
121

 
$
—

 
$
358

 
Total
 
$
259

 
$
122

 
$
111

 
$
492

Liabilities:
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
1

 
$
—

 
$
—

 
$
1

 
Natural gas
 
19

 
—

 
176

 
195

 
Power
 
—

 
1

 
25

 
26

 
Uranium
 
—

 
—

 
1

 
1

 
Total
 
$
20

 
$
1

 
$
202

 
$
223

(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.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012, and 2011:
  
 
Net Derivative Commodity Contracts
  
 
2012
 
2011
Fuel oils:
 
 
 
 
Beginning balance at January 1
 
$
3

 
$
30

Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(1
)
 
19

Total realized and unrealized gains (losses)
 
(1
)
 
19

Purchases
 
7

 
4

Sales
 
(3
)
 
(1
)
Settlements
 
(2
)
 
(30
)
Transfers into Level 3
 
1

 
—

Transfers out of Level 3
 
—

 
(19
)
Ending balance at December 31
 
$
5

 
$
3

Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
(1
)
 
$
(11
)
Natural gas:
 
 
 
 
Beginning balance at January 1
 
$
(174
)
 
$
(148
)
Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(27
)
 
(115
)
Total realized and unrealized gains (losses)
 
(27
)
 
(115
)
Purchases
 
—

 
1

Sales
 
—

 
(1
)
Settlements
 
16

 
89

Transfers out of Level 3
 
185

 
—

Ending balance at December 31
 
$
—

 
$
(174
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
—

 
$
(78
)
Power:
 
 
 
 
Beginning balance at January 1
 
$
81

 
$
19

Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(175
)
 
55

Total realized and unrealized gains (losses)
 
(175
)
 
55

Purchases
 
21

 
30

Sales
 
(1
)
 
(1
)
Settlements
 
(22
)
 
(22
)
Transfers into Level 3
 
—

 
(1
)
Transfers out of Level 3
 
(4
)
 
1

Ending balance at December 31
 
$
(100
)
 
$
81

Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
(175
)
(a) 
$
(25
)
Uranium:
 
 
 
 
Beginning balance at January 1
 
$
(1
)
 
$
2

Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(3
)
Total realized and unrealized gains (losses)
 
(2
)
 
(3
)
Purchases
 
—

 
(1
)
Settlements
 
1

 
1

Ending balance at December 31
 
$
(2
)
 
$
(1
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
(1
)
 
$
—

(a)
The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois swap contracts, which expire in May 2032.

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended December 31, 2012 and the previous reporting period ended December 31, 2011. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the years ended December 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the years ended December 31, 2012, and 2011:
 
2012
 
2011
Derivative commodity contracts:



Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
1

 
$
—

Transfers out of Level 3 / Transfers into Level 1 - Fuel oils
—

 
(19
)
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
185

 
—

Transfers into Level 3 / Transfers out of Level 2 - Power
—

 
(1
)
Transfers out of Level 3 / Transfers into Level 2 - Power
(4
)
 
1

Net fair value of Level 3 transfers
$
182

 
$
(19
)
See Note 11 - Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 2012, as well as a table summarizing the changes in Level 3 plan assets during 2012. See Note 17 - Impairment and Other Charges for the fair value hierarchy discussion related to Ameren's impairment charges.
The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Ameren's carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the fair value hierarchy as they are valued based on similar market transactions. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 2012, and 2011:
  
2012
 
2011
  
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt and capital lease obligations (including current portion)
$
6,157

 
$
7,110

 
$
6,032

 
$
6,961

Preferred stock(a)
142

 
123

 
142

 
92

(a)
Preferred stock along with the noncontrolling interest of EEI is recorded in "Noncontrolling Interests" on the consolidated balance sheet.
Nuclear Decommissioning Trust Fund Investments
NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS
NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS
Ameren Missouri has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway energy center. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 2012, and 2011. See Note 10 - Callaway Energy Center for additional information.
Investments in the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities, with the balance invested in debt securities.
The following table presents proceeds from the sale and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and losses resulting from those sales for the years ended December 31, 2012, 2011, and 2010:
 
2012
 
2011
 
2010
Proceeds from sales and maturities
$
384

 
$
199

 
$
256

Gross realized gains
6

 
5

 
5

Gross realized losses
2

 
4

 
4


Net realized and unrealized gains and losses are deferred and recorded as regulatory assets or regulatory liabilities on Ameren’s consolidated balance sheet. This reporting is consistent with the method used to account for the decommissioning costs recovered in rates. Gains or losses associated with assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which are expected to be reflected in electric rates paid by Ameren Missouri’s customers. See Note 2 - Rate and Regulatory Matters.
The following table presents the costs and fair values of investments in debt and equity securities in Ameren Missouri’s nuclear decommissioning trust fund at December 31, 2012, and 2011:
Security Type
Cost
 
Gross Unrealized Gain
 
Gross Unrealized Loss
 
Fair Value
2012
 
 
 
 
 
 
 
Debt securities
$
133

 
$
8

 
(a)

 
$
141

Equity securities
145

 
130

 
11

 
264

Cash
1

 
—

 
—

 
1

Other(b)
2

 
—

 
—

 
2

Total
$
281

 
$
138

 
$
11

 
$
408

2011
 
 
 
 
 
 
 
Debt securities
$
114

 
$
7

 
(a)

 
$
121

Equity securities
145

 
101

 
12

 
234

Cash
3

 
—

 
—

 
3

Other(b)
(1
)
 
—

 
—

 
(1
)
Total
$
261

 
$
108

 
$
12

 
$
357

(a)
Amount less than $1 million.
(b)
Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest receivables.
The following table presents the costs and fair values of investments in debt securities in Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2012:
 
Cost
 
Fair Value
Less than 5 years
$
78

 
$
79

5 years to 10 years
32

 
35

Due after 10 years
23

 
27

Total
$
133

 
$
141


We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund, recorded as regulatory assets as discussed above. Decommissioning will not occur until the operating license for our nuclear energy center expires. Ameren Missouri submitted a license extension application to the NRC to extend the Callaway energy center’s operating license to 2044. The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in Ameren Missouri's nuclear decommissioning trust fund. They are aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position at December 31, 2012:
  
Less than 12 Months
 
12 Months or Greater
 
Total
  
Fair Value
 
Gross
Unrealized
Losses
 
Fair Value
 
Gross
Unrealized
Losses
 
Fair Value
 
Gross
Unrealized
Losses
Debt securities
$
17

 
$ (a)

 
$ (a)

 
$ (a)

 
$
17

 
$ (a)

Equity securities
7

 
1

 
14

 
10

 
21

 
11

Total
$
24

 
$
1

 
$
14

 
$
10

 
$
38

 
$
11

(a)
Amount less than $1 million.
Callaway Energy Center
CALLAWAY ENERGY CENTER
CALLAWAY ENERGY CENTER
Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren and other utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated by those plants and sold. The NWPA also requires the DOE to review the nuclear waste fee against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren and other utilities have entered into standard contracts with the federal government. The government, represented by the DOE, is responsible for implementing these provisions of the NWPA. Consistent with the NWPA and its standard contract, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center.
Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government has acknowledged since at least 1994 that it would not meet that deadline. The federal government is not currently predicting when it will begin to meet its disposal obligation. Ameren Missouri has sufficient installed capacity at its Callaway energy center to store the spent nuclear fuel generated at Callaway through 2020 and has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s current licensed life.
Until January 2009, the DOE program provided for spent nuclear fuel disposal to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. In January 2009, the federal government announced that a repository at Yucca Mountain was unworkable and took steps to terminate the Yucca Mountain program, while acknowledging the federal government’s continuing obligation to dispose of utilities’ spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund.
In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel in response to the recommendation contained in the advisory commission's report. The DOE's plan calls for a pilot interim storage facility to begin operation with an initial focus on accepting spent nuclear fuel from shutdown reactor sites by 2021. By 2025, a larger interim storage facility would be available and would be co-located with the pilot facility. The plan also proposes to site a permanent geological repository by 2026, to characterize the site and to design and to license the repository by 2042, and to begin operation by 2048.
In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit seeking the suspension of the one mill nuclear waste fee, alleging that the DOE failed to undertake an appropriate fee adequacy review reflecting the current unsettled state of the nuclear waste program. In a June 2012 decision, the court ruled that DOE's fee adequacy review was legally inadequate and remanded the matter to the DOE. Although the court ruled it has the power to direct the DOE to suspend the fee, the court decided that it was premature to do so. Instead, the court ordered the DOE to provide within six months a revised assessment of the amount that should be collected. On January 19, 2013, the DOE issued the revised assessment required by the court. The DOE determined that “neither insufficient nor excess revenues are being collected” and it proposed no adjustment to the one mill nuclear waste fee.
The DOE's delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operation of the energy center.
As a result of DOE's failure to begin to dispose of the utilities' spent nuclear fuel and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have also sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. In June 2011, the parties reached a settlement that included a payment to Ameren Missouri of $11 million for spent fuel storage and related costs through 2010 and, thereafter, annual payment of such costs after they are incurred through 2013 or any other mutually agreed extension. As a result of this settlement agreement, Ameren recorded a pretax reduction of $2 million and $2 million to its “Operating Expenses - Depreciation and amortization” and “Operating Expenses - Other operations and maintenance” expense line items, respectively, on its consolidated statement of income (loss) for the year ended December 31, 2011. Ameren reduced its property and plant net assets by $7 million for the year ended December 31, 2011. Ameren Missouri received the 2011 cost reimbursement of $1 million and reduced its property and plant net assets by this amount in 2012. In March 2013, Ameren Missouri plans to submit approximately $5 million of 2012 costs to the DOE for reimbursement under the settlement agreement.
In December 2011, Ameren Missouri filed a license extension application with the NRC to extend its Callaway energy center's operating license from 2024 to 2044. There is no deadline by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in approving license extensions are rules dealing with the storage of spent nuclear fuel at the reactor site and with the NRC's confidence that permanent disposal of spent nuclear fuel will be available when needed. In a June 2012 decision, the United States Court of Appeals for the District of Columbia Circuit vacated these rules and remanded the case to the NRC, holding that the NRC's obligations under the National Environmental Policy Act required a more thorough environmental analysis in support of the NRC's waste confidence decision. In June 2012, a number of groups petitioned the NRC to suspend final licensing decisions in certain NRC licensing proceedings, including the Callaway license extension, until the NRC completed its proceedings on the vacated rules. In August 2012, the NRC stated that it would not issue licenses dependent on the vacated rules until it appropriately addressed the court's remand. In September 2012, the NRC directed its staff to issue, within two years, a generic environmental impact statement and a final rule to address the court's ruling. The NRC also stated that a site-specific analysis of these issues could be conducted in rare circumstances. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility by 2016.
Electric utility rates charged to customers provide for the recovery of the Callaway energy center's decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the nuclear center, ending with the expiration of the energy center's current operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren has recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 2012, 2011, and 2010. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. The last cost study and funding analysis were filed with the MoPSC in September 2011. In October 2012, the MoPSC issued an order approving the stipulation and agreement between Ameren Missouri and the MoPSC staff that maintained the current rate of deposits to the trust fund and the rate of return assumptions used in the analysis. If Ameren Missouri's operating license extension application is approved by the NRC, a revised funding analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension at the time the next triennial cost study and funding analysis is approved by the MoPSC. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center's decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's consolidated balance sheet. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability.
See Note 2 - Rate and Regulatory Matters for additional information related to the Callaway energy center.
Retirement Benefits
RETIREMENT BENEFITS
RETIREMENT BENEFITS
The primary objective of the Ameren pension and postretirement benefit plans is to provide eligible employees with pension and postretirement health care and life insurance benefits. Ameren offers defined benefit pension and postretirement benefit plans covering substantially all of its employees. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans. Ameren’s qualified pension plan is the Ameren Retirement Plan. Ameren also has an unfunded non-qualified pension plan, the Ameren Supplemental Retirement Plan, which is available for certain management employees and retirees to provide a supplemental benefit when their qualified pension plan benefits are reduced to comply with Internal Revenue Code limitations. Ameren’s other postretirement plans are the Ameren Retiree Medical Plan and the Ameren Group Life Insurance Plan. Separately, EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. EEI’s pension plan is the Revised Retirement Plan for Employees of Electric Energy, Inc. EEI’s other postretirement plans are the Group Insurance Plan for Management Employees of Electric Energy, Inc. and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. Nonaffiliated Ameren companies do not participate in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under this agreement, Ameren will retain the pension and postretirement benefits obligations associated with current and former employees of AER that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. This noncurrent obligation is reflected on Ameren's consolidated balance sheet as "Pension and other postretirement benefits." IPH will assume the pension and other postretirement benefit obligations associated with EEI's current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. These obligations are estimated at $40 million and are included in "Current liabilities of discontinued operations" on Ameren's consolidated balance sheet. In addition to these obligations, IPH will acquire the estimated $15 million asset at December 31, 2012, relating to the overfunded status of one of EEI's postretirement plans. This asset is included in "Current assets of discontinued operations" on Ameren's consolidated balance sheet. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information. The disclosures in this note only reflect continuing operations. Therefore, the impacts of the EEI plans are not reflected.
Ameren recognizes the under-funded status of its pension and postretirement plans as a liability on its consolidated balance sheet, with offsetting entries to accumulated OCI and regulatory assets, in accordance with authoritative accounting guidance. The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2012, and 2011. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 2012, and 2011, that have not been recognized in net periodic benefit costs.
  
2012
 
2011
  
Pension Benefits
 
Postretirement
Benefits
 
Pension Benefits
 
Postretirement
Benefits
Accumulated benefit obligation at end of year
$
3,829

 
(a)

 
$
3,553

 
(a)

Change in benefit obligation:
 
 
 
 
 
 
 
Net benefit obligation at beginning of year
$
3,764

 
$
1,145

 
$
3,366

 
$
1,036

Service cost
81

 
22

 
73

 
20

Interest cost
166

 
47

 
175

 
54

Plan amendments(b)
—

 
—

 
(16
)
 
—

Participant contributions
—

 
16

 
—

 
18

Actuarial (gain) loss
240

 
(10
)
 
335

 
71

Benefits paid
(200
)
 
(69
)
 
(169
)
 
(63
)
Early retiree reinsurance program receipt
(a)

 
2

 
(a)

 
3

Federal subsidy on benefits paid
(a)

 
4

 
(a)

 
6

Net benefit obligation at end of year
4,051

 
1,157

 
3,764

 
1,145

Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
2,814

 
836

 
2,664

 
735

Actual return on plan assets
385

 
104

 
223

 
8

Employer contributions
128

 
45

 
96

 
129

Federal subsidy on benefits paid
(a)

 
4

 
(a)

 
6

Early retiree reinsurance program receipt
(a)

 
2

 
(a)

 
3

Participant contributions
—

 
16

 
—

 
18

Benefits paid
(200
)
 
(69
)
 
(169
)
 
(63
)
Fair value of plan assets at end of year
3,127

 
938

 
2,814

 
836

Funded status - deficiency
924

 
219

 
950

 
309

Accrued benefit cost at December 31
$
924

 
$
219

 
$
950

 
$
309

Amounts recognized in the consolidated balance sheet consist of:
 
 
 
 
 
 
 
Current liability
$
3

 
$
2

 
$
3

 
$
3

Noncurrent liability
921

 
217

 
947

 
306

Net liability recognized
$
924

 
$
219

 
$
950

 
$
309

Amounts recognized in regulatory assets consist of:
 
 
 
 
 
 
 
Net actuarial loss
$
699

 
$
103

 
$
734

 
$
177

Prior service cost (credit)
(6
)
 
(24
)
 
(7
)
 
(28
)
Transition obligation
—

 
—

 
—

 
2

Amounts (pretax) recognized in accumulated OCI consist of:
 
 
 
 
 
 
 
Net actuarial loss
65

 
5

 
54

 
5

Prior service cost (credit)
(14
)
 
(6
)
 
(16
)
 
(7
)
Total
$
744

 
$
78

 
$
765

 
$
149

(a)
Not applicable.
(b)
In 2011, Ameren’s pension plan was amended to adjust the calculation of the future benefit obligation of approximately 430 labor union-represented employees from a traditional, final pay formula to a cash balance formula.
The following table presents the assumptions used to determine our benefit obligations at December 31, 2012, and 2011:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2012
 
2011
Discount rate at measurement date
4.00
%
 
4.50
%
 
4.00
%
 
4.50
%
Increase in future compensation
3.50

 
3.50

 
3.50

 
3.50

Medical cost trend rate (initial)
—

 
—

 
5.00

 
5.50

Medical cost trend rate (ultimate)
—

 
—

 
5.00

 
5.00

Years to ultimate rate
0

 
0

 
0

 
1 year


Ameren determines discount rate assumptions by identifying a theoretical settlement portfolio of high-quality corporate bonds sufficient to provide for a plan's projected benefit payments, pursuant to authoritative accounting guidance on the determination of discount rates used for defined benefit plan obligations. The settlement portfolio of bonds is selected from a pool of over 600 high-quality corporate bonds.  A single discount rate is then determined that results in a discounted value of the plan's benefit payments that equates to the market value of the selected bonds.
Funding
Pension benefits are based on the employees’ years of service and compensation. Ameren’s pension plan is funded in compliance with income tax regulations and federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plan at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at December 31, 2012, its investment performance in 2012, and its pension funding policy, Ameren expects to make annual contributions of $50 million to $150 million in each of the next five years, with aggregate estimated contributions of $525 million. These amounts are estimates. The estimates may change based on actual investment performance, changes in interest rates, changes in our assumptions, any pertinent changes in government regulations, and any voluntary contributions. Our funding policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.
The following table presents the cash contributions made to our defined benefit retirement plan and to our postretirement plans during 2012, 2011, and 2010:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
$
128

 
$
96

 
$
81

 
$
45

 
$
129

 
$
36

Investment Strategy and Policies
Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. The investment committee, to the extent authority is delegated to it by the finance committee of Ameren’s board of directors, implements investment strategy and asset allocation guidelines for the plan assets. The investment committee includes members of senior management. The investment committee’s goals are twofold: first, to ensure that sufficient funds are available to provide the benefits at the time they are payable and second, to maximize total return on plan assets and minimize expense volatility consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class. As appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. The investment committee regularly monitors manager performance and compliance with investment guidelines.
The expected return on plan assets assumption is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Projected rates of return for each asset class were estimated after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared with benchmark returns and for the effect of expenses paid from plan assets. Ameren will utilize an expected return on plan assets for its pension plan assets and postretirement plan assets of 7.50% and 7.25%, respectively, in 2013. No plan assets are expected to be returned to Ameren during 2013.
Ameren’s investment committee strives to assemble a portfolio of diversified assets that does not create a significant concentration of risks. The investment committee develops asset allocation guidelines between asset classes, and it creates diversification through investments in assets that differ by type (equity, debt, real estate, private equity), duration, market capitalization, country, style (growth or value) and industry, among other factors. The diversification of assets is displayed in the target allocation table below. The investment committee also routinely rebalances the plan assets to adhere to the diversification goals. The investment committee’s strategy reduces the concentration of investment risk; however, Ameren is still subject to overall market risk. The following table presents our target allocations for 2013 and our pension and postretirement plans’ asset categories as of December 31, 2012, and 2011.
Asset
Category
Target Allocation
2013
 
Percentage of Plan Assets at December  31,
2012
 
2011
Pension Plan:
 
 
 
 
 
Cash and cash equivalents
0 - 5  %
 
2
%
 
2
%
Equity securities:
 
 
 
 
 
U.S. large capitalization
29 - 39
 
34

 
33
%
U.S. small and mid-capitalization
2 - 12
 
7

 
7
%
International and emerging markets
9 - 19
 
13

 
11
%
Total equity
50 - 60
 
54

 
51
%
Debt securities
35 - 45
 
39

 
42
%
Real estate
0 -   9  
 
4

 
4
%
Private equity
0 -   4  
 
1

 
1
%
Total
 
 
100
%
 
100
%
Postretirement Plans:
 
 
 
 
 
Cash and cash equivalents
0 - 10 %
 
4
%
 
4
%
Equity securities:
 
 
 
 
 
U.S. large capitalization
33 - 43
 
40
%
 
38
%
U.S. small and mid-capitalization
3 - 13
 
8
%
 
8
%
International
10 - 20
 
14
%
 
13
%
Total equity
55 - 65
 
62
%
 
59
%
Debt securities
30 - 40
 
34
%
 
37
%
Total
 
 
100
%
 
100
%

In general, the United States large capitalization equity investments are passively managed or indexed, whereas the international, emerging markets, United States small capitalization, and United States mid-capitalization equity investments are actively managed by investment managers. Debt securities include a broad range of fixed income vehicles. Debt security investments in high-yield securities, emerging market securities, and non-United States dollar-denominated securities are owned by the plans, but in limited quantities to reduce risk. Most of the debt security investments are under active management by investment managers. Real estate investments include private real estate vehicles; however, Ameren does not, by policy, hold direct investments in real estate property. Ameren’s investment in private equity funds consists of 10 different limited partnerships, with invested capital ranging from $0.1 million to $5 million each, which invest primarily in a diversified number of small United States-based companies. No further commitments may be made to private equity investments without approval by the finance committee of the board of directors. Additionally, Ameren’s investment committee allows investment managers to use derivatives, such as index futures, exchange traded funds, foreign exchange futures, and options, in certain situations, to increase or to reduce market exposure in an efficient and timely manner.
Fair Value Measurements of Plan Assets
Investments in the pension and postretirement benefit plans were stated at fair value as of December 31, 2012. The fair value of an asset is the amount that would be received upon sale in an orderly transaction between market participants at the measurement date. Cash and cash equivalents have initial maturities of three months or less and are recorded at cost plus accrued interest. The carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments. Investments traded in active markets on national or international securities exchanges are valued at closing prices on the last business day on or before the measurement date. Securities traded in over-the-counter markets are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Derivative contracts are valued at fair value, as determined by the investment managers (or independent third parties on behalf of the investment managers), who use proprietary models and take into consideration exchange quotations on underlying instruments, dealer quotations, and other market information. The fair value of real estate is based on annual appraisal reports prepared by an independent real estate appraiser.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2012:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
1

 
$
28

 
$
—

 
$
29

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
83

 
1,007

 
—

 
1,090

U.S. small and mid-capitalization
235

 
—

 
—

 
235

International and emerging markets
134

 
301

 
—

 
435

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
832

 
—

 
832

Municipal bonds
—

 
176

 
—

 
176

U.S. treasury and agency securities
—

 
250

 
—

 
250

Other
—

 
17

 
—

 
17

Real estate
—

 
—

 
118

 
118

Private equity
—

 
—

 
19

 
19

Derivative assets
—

 
—

 
—

 
—

Derivative liabilities
(1
)
 
—

 
—

 
(1
)
Total
$
452

 
$
2,611

 
$
137

 
$
3,200

Less: Medical benefit assets at December 31(a)
 
 
 
 
 
 
(102
)
Plus: Net receivables at December 31(b)
 
 
 
 
 
 
29

Fair value of pension plans assets at year end
 
 
 
 
 
 
$
3,127

(a)
Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation.
(b)
Receivables related to pending security sales, offset by payables related to pending security purchases.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2011:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
—

 
$
30

 
$
—

 
$
30

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
72

 
901

 
—

 
973

U.S. small and mid-capitalization
202

 
—

 
—

 
202

International and emerging markets
115

 
208

 
—

 
323

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
794

 
—

 
794

Municipal bonds
—

 
176

 
—

 
176

U.S. treasury and agency securities
—

 
230

 
—

 
230

Other
—

 
23

 
—

 
23

Real estate
—

 
—

 
108

 
108

Private equity
—

 
—

 
23

 
23

Derivative assets
1

 
—

 
—

 
1

Derivative liabilities
(1
)
 
—

 
—

 
(1
)
Total
$
389

 
$
2,362

 
$
131

 
$
2,882

Less: Medical benefit assets at December 31(a)
 
 
 
 
 
 
(91
)
Plus: Net receivables at December 31(b)
 
 
 
 
 
 
23

Fair value of pension plans assets at year end
 
 
 
 
 
 
$
2,814

(a)
Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation.
(b)
Receivables related to pending security sales, offset by payables related to pending security purchases.
The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the fair value hierarchy for each of the years ended December 31, 2012, and 2011:
 
Beginning
Balance at
January 1,
 
Actual Return on
Plan Assets Related
to Assets Still Held
at the Reporting Date
 
Actual Return on
Plan Assets Related
to Assets Sold
During the Period
 
Purchases,
Sales, and
Settlements, net
 
Net
Transfers
into (out of)
of Level 3
 
Ending Balance at
December 31,
2012:
 
 
 
 
 
 
 
 
 
 
 
Real estate
$
108

 
$
7

 
$
—

 
$
3

 
$
—

 
$
118

Private equity
23

 
(7
)
 
8

 
(5
)
 
—

 
19

2011:
 
 
 
 
 
 
 
 
 
 
 
Real estate
$
98

 
$
10

 
$
—

 
$
—

 
$
—

 
$
108

Private equity
28

 
(10
)
 
11

 
(6
)
 
—

 
23


The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2012:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
83

 
$
—

 
$
—

 
$
83

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
245

 
88

 
—

 
333

U.S. small and mid-capitalization
66

 
—

 
—

 
66

International
45

 
69

 
—

 
114

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
88

 
—

 
88

Municipal bonds
—

 
91

 
—

 
91

U.S. treasury and agency securities
—

 
67

 
—

 
67

Asset-backed securities
—

 
18

 
—

 
18

Other
—

 
22

 
—

 
22

Total
$
439

 
$
443

 
$
—

 
$
882

Plus: Medical benefit assets at December 31(a)
 
 
 
 
 
 
102

Less: Net payables at December 31(b)
 
 
 
 
 
 
(46
)
Fair value of postretirement benefit plans assets at year end
 
 
 
 
 
 
$
938

(a)
Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.
(b)
Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2011:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
1

 
$
65

 
$
—

 
$
66

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
206

 
78

 
—

 
284

U.S. small and mid-capitalization
57

 
—

 
—

 
57

International
38

 
56

 
—

 
94

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
71

 
—

 
71

Municipal bonds
—

 
80

 
—

 
80

U.S. treasury and agency securities
—

 
69

 
—

 
69

Asset-backed securities
—

 
23

 
—

 
23

Other
—

 
34

 
—

 
34

Total
$
302

 
$
476

 
$
—

 
$
778

Plus: Medical benefit assets at December 31(a)
 
 
 
 
 
 
91

Less: Net payables at December 31(b)
 
 
 
 
 
 
(33
)
Fair value of postretirement benefit plans assets at year end
 
 
 
 
 
 
$
836

(a)
Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.
(b)
Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.
Net Periodic Benefit Cost
The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit plans during 2012, 2011, and 2010:
 
Pension Benefits
 
Postretirement Benefits
2012
 
 
 
Service cost
$
81

 
$
22

Interest cost
166

 
47

Expected return on plan assets
(208
)
 
(56
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
(3
)
 
(6
)
Actuarial loss
75

 
5

Net periodic benefit cost
$
111

 
$
14

2011
 
 
 
Service cost
$
73

 
$
20

Interest cost
175

 
54

Expected return on plan assets
(211
)
 
(50
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
(1
)
 
(6
)
Actuarial loss
41

 
3

Net periodic benefit cost
$
77

 
$
23

2010
 
 
 
Service cost
$
65

 
$
18

Interest cost
181

 
58

Expected return on plan assets
(208
)
 
(51
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
6

 
(6
)
Actuarial loss
18

 
—

Net periodic benefit cost
$
62

 
$
21

The current year expected return on plan assets is determined primarily by adjusting the prior-year market-related asset value for current year contributions, disbursements, and expected return, plus 25% of the actual return in excess of (or less than) expected return for the four prior years.
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in 2013 are as follows:
  
Pension Benefits
 
Postretirement Benefits
  
Ameren
 
Ameren
Regulatory assets:
 
 
 
Prior service cost (credit)
$
(1
)
 
$
(4
)
Net actuarial loss
97

 
19

Accumulated OCI:
 
 
 
Prior service cost (credit)
(2
)
 
(1
)
Net actuarial loss
5

 
—

Total
$
99

 
$
14

Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan amendment. The net actuarial loss subject to amortization is amortized on a straight-line basis over 10 years.
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, as of December 31, 2012, are as follows:
  
Pension Benefits
 
Postretirement Benefits
  
Paid from
Qualified
Trust
 
Paid from
Company
Funds
 
Paid from
Qualified
Trust
 
Paid from
Company
Funds
 
Federal
Subsidy
2013
$
229

 
$
3

 
$
58

 
$
2

 
$
3

2014
236

 
3

 
60

 
2

 
3

2015
239

 
3

 
62

 
2

 
4

2016
245

 
3

 
65

 
2

 
4

2017
248

 
3

 
68

 
2

 
4

2018 - 2022
1,279

 
13

 
384

 
11

 
19


The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2012, 2011, and 2010:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Discount rate at measurement date
4.50
%
 
5.25
%
 
5.75
%
 
4.50
%
 
5.25
%
 
5.75
%
Expected return on plan assets
7.75

 
8.00

 
8.00

 
7.50

 
7.75

 
8.00

Increase in future compensation
3.50

 
3.50

 
3.50

 
3.50

 
3.50

 
3.50

Medical cost trend rate (initial)
—

 
—

 
—

 
5.50

 
6.00

 
6.50

Medical cost trend rate (ultimate)
—

 
—

 
—

 
5.00

 
5.00

 
5.00

Years to ultimate rate
0

 
0

 
0

 
1 year

 
2 years

 
3 years


The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
  
Pension Benefits
 
Postretirement Benefits
  
Service Cost
and Interest
Cost
 
Projected
Benefit
Obligation
 
Service Cost
and Interest
Cost
 
Postretirement
Benefit
Obligation
0.25% decrease in discount rate
$
(2
)
 
$
121

 
$
—

 
$
34

0.25% increase in salary scale
2

 
13

 
—

 
—

1.00% increase in annual medical trend
—

 
—

 
—

 
36

1.00% decrease in annual medical trend
—

 
—

 
(1
)
 
(34
)

Other
Ameren sponsors a 401(k) plan for eligible employees. The Ameren 401(k) plan covered all eligible employees at December 31, 2012. The plan allowed employees to contribute a portion of their compensation in accordance with specific guidelines. Ameren matched a percentage of the employee contributions up to certain limits. Ameren incurred costs of $28 million, $28 million, and $27 million in relation to the matching contribution for the years ended December 31, 2012, 2011, and 2010, respectively.
Stock-Based Compensation
STOCK-BASED COMPENSATION
STOCK-BASED COMPENSATION
Ameren’s long-term incentive plan is available to for eligible employees, under Ameren's shareholder-approved 2006 Omnibus Incentive Compensation Plan (2006 Plan), which became effective May 2, 2006. The 2006 Plan provides for a maximum of 4 million common shares to be available for grant to eligible employees and directors. The 2006 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.
A summary of nonvested shares at December 31, 2012, and changes during the year ended December 31, 2012, under the 2006 Plan are presented below:
  
Performance Share Units
  
Share
Units
 
Weighted-average
Fair Value per Unit
Nonvested at January 1, 2012
1,156,831

 
$
31.70

Granted(a)
717,151

 
35.68

Unearned or forfeited(b)
(477,928
)
 
32.04

Earned and vested(c)
(203,567
)
 
34.01

Nonvested at December 31, 2012
1,192,487

 
$
33.56

(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b)
Includes share units granted in 2010 that were not earned based on performance provisions of the award grants.
(c)
Includes share units granted in 2010 that vested as of December 31, 2012, that were earned pursuant to the provisions of the award grants. Also includes share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.
Ameren recorded compensation expense of $22 million, $13 million, and $11 million for the years ended December 31, 2012, 2011, and 2010, respectively, and a related tax benefit of $8 million, $5 million and $4 million for the years ended December 31, 2012, 2011, and 2010, respectively. Ameren settled performance share units and restricted shares of $11 million, $4 million, and $2 million for the years ended December 31, 2012, 2011, and 2010. All outstanding restricted shares vested as of the end of 2011. There were no significant compensation costs capitalized related to the performance share units during the years ended December 31, 2012, 2011, and 2010. As of December 31, 2012, total compensation cost of $21 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 20 months.
Performance Share Units
Performance share units have been granted under the 2006 Plan. A share unit vests and entitles an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, certain specified performance or market conditions have been met and the individual remains employed by Ameren. The exact number of shares issued pursuant to a share unit varies from 0% to 200% of the target award, depending on actual company performance relative to the performance goals.
The fair value of each share unit awarded in January 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren's closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.
The fair value of each share unit awarded in January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren’s closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The simulations can produce a greater fair value for the share unit than the closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren’s attainment of three-year average earnings per share threshold during the performance period.
Income Taxes
INCOME TAXES
INCOME TAXES
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2012, 2011, and 2010:
 
2012
2011
2010
Statutory federal income tax rate:
35
 %
35
 %
35
 %
Increases (decreases) from:
 
 
 
Depreciation differences
(1
)
(1
)
(3
)
Amortization of investment tax credit
(1
)
(1
)
(1
)
State tax
5

4

5

Reserve for uncertain tax positions
—

1

(1
)
Tax credits
—

(1
)
(1
)
Change in federal tax law(a)
—

—

2

Other permanent items(b)
(1
)
—

—

Effective income tax rate
37
 %
37
 %
36
 %
(a)
Relates to change in taxation of prescription drug benefits to retiree participants from the enactment in 2010 of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.
(b)
Permanent items are treated differently for book and tax purposes and primarily include nondeductible expense related to lobbying and stock issuance expenses.
The following table presents the components of income tax expense for the years ended December 31, 2012, 2011, and 2010:
 
2012
2011
2010
Current taxes:
 
 
 
Federal
$
40

$
(6
)
$
3

State
9

(2
)
(1
)
Deferred taxes:
 
 
 
Federal
205

206

247

State
61

53

32

Deferred investment tax credits, amortization
(6
)
(6
)
(7
)
Total income tax expense
$
309

$
245

$
274


The Illinois corporate income tax rate increased from 7.3% to 9.5%, starting in January 2011. The tax rate is scheduled to decrease to 7.75% in 2015, and it is scheduled to return to 7.3% in 2025. This corporate income tax rate increase in Illinois increased current income tax expense in 2011 by $6 million. As a result of this corporate income tax rate increase, accumulated deferred tax balances were revalued, resulting in a decrease in deferred tax expense of $2 million in 2011.
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2012, and 2011:
 
2012
2011
Accumulated deferred income taxes, net liability (asset):
 
 
Plant related
$
3,512

$
3,162

Deferred intercompany tax gain/basis step-up
39

54

Regulatory assets, net
73

73

Deferred employee benefit costs
(323
)
(320
)
Purchase accounting
(27
)
(28
)
ARO
(17
)
(12
)
Other(a)
(251
)
(217
)
Total net accumulated deferred income tax liabilities
$
3,006

$
2,712

(a)
Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below.
The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2012:
 
2012
Net operating loss carryforwards:
 
Federal(a)
$
173

State(b)
27

Total net operating loss carryforwards
$
200

Tax credit carryforwards:
 
Federal(c)
$
86

State(d)
25

State valuation allowance(e)
(2
)
Total tax credit carryforwards
$
109

(a)
These will begin to expire in 2028.
(b)
These will begin to expire in 2017.
(c)
These will begin to expire in 2029.
(d)
These will begin to expire in 2013.
(e)
This balance increased by $1 million during 2012.
Uncertain Tax Positions
A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 2012, 2011, and 2010, is as follows:
 
2012
2011
2010
Unrecognized tax benefits - beginning of year
$
148

$
246

$
135

Increases based on tax positions prior to current year
5

22

72

Decreases based on tax positions prior to current year
(13
)
(125
)
(38
)
Increases based on tax positions related to current year
17

17

77

Changes related to settlements with taxing authorities
—

(10
)
—

Decreases related to the lapse of statute of limitations
(1
)
(2
)
—

Unrecognized tax benefits - end of year
$
156

$
148

$
246

Total unrecognized tax benefits that, if recognized, would affect the effective tax rates
$
1

$
1

$
—


The Ameren Companies recognize interest charges (income) and penalties accrued on tax liabilities on a pretax basis as interest charges (income) or miscellaneous expense, respectively, in the statements of income.
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 2012, 2011, and 2010, is as follows:
 
2012
2011
2010
Liability for interest - beginning of year
$
5

$
17

$
8

Interest charges (income)
1

(11
)
9

Interest payment
—

(1
)
—

Liability for interest - end of year
$
6

$
5

$
17


As of December 31, 2012, 2011, and 2010, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax benefits.
In the second quarter of 2011, a final settlement for the years 2005 and 2006 was reached with the Internal Revenue Service. It resulted in a reduction in uncertain tax liabilities of $39 million. Ameren’s federal income tax returns for the years 2007 through 2010 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2011 is currently under examination.
It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2010. This settlement, primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of approximately $143 million. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals Office settlement discussed above, would be material to their results of operations, financial position, or liquidity.
State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation.
Related Party Transactions
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS WITH NEW AER
Ameren and its subsidiaries have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are eliminated in consolidation for Ameren’s financial statements. Below are the material related party agreements with New AER, with the exception of certain parent company guarantees not affiliated with New AER noted below.
Put Option Agreement and Guarantee
On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gave Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin gas-fired energy centers. If Genco exercised the put option, the purchase price for all three energy centers would be the greater of $100 million or the fair market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to Genco within one business day. If Genco exercised the put option, the closing of the sale of all three energy centers would be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million.
The put option agreement required AERG to secure and maintain an Ameren guarantee of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guarantee agreement on March 28, 2012. The guarantee shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or until the put option agreement is terminated and no further payments are owed by AERG to Genco.
See Note 16 - Divestiture Transactions and Discontinued Operations for information regarding amendments to the put option agreement and Ameren guarantee, as well as the exercise of the put option, in 2013.
Electric Power Supply Agreements
Capacity Supply Agreements
Ameren Illinois, as an electric load-serving entity, must acquire capacity sufficient to meet its obligations to customers.
In 2009, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2009, through May 31, 2012. Marketing Company was among the winning suppliers in the capacity RFP process. In April 2009, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $4 million, $9 million, and $8 million for the 12 months ending May 31, 2010, 2011, and 2012, respectively.
In 2010, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2010, through May 31, 2013. Marketing Company was among the winning suppliers in the capacity RFP process. In April 2010, Marketing Company contracted to supply a portion of Ameren Illinois’ capacity requirements to Ameren Illinois for $1 million, $2 million, and $3 million for the 12 months ending May 31, 2011, 2012, and 2013, respectively.
During 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity for the period from June 1, 2012, through May 31, 2015. Marketing Company was among the winning suppliers in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois' capacity requirements for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively.
Energy Swaps and Energy Products
Ameren Illinois, as an electric load-serving entity, must acquire energy sufficient to meet its obligations to customers.
In 2009, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps from June 1, 2009, through May 31, 2011. Marketing Company was a winning supplier in the financial energy swap RFP process. In May 2009, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 80,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2010 and for approximately 89,000 megawatthours at approximately $48 per megawatthour during the 12 months ending May 31, 2011.
In 2010, Ameren Illinois used a RFP process, administered by the IPA, to procure financial energy swaps for the period from June 1, 2010, through May 31, 2013. Marketing Company was a winning supplier in the financial energy swap RFP process. In May 2010, Marketing Company entered into financial instruments that fixed the price that Ameren Illinois paid for approximately 924,000 megawatthours at approximately $33 per megawatthour during the 12 months ending May 31, 2011 and for approximately 296,000 megawatthours at approximately $40 per megawatthour during the 12 months ending May 31, 2012.
In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products that will settle physically from June 1, 2011, through May 31, 2014. Marketing Company was a winning supplier in Ameren Illinois’ energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements by which Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the 12 months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2013, and approximately 650,000 megawatthours at approximately $42 per megawatthour during the 12 months ending May 31, 2014.
In February 2012, a rate stability procurement for energy products that will settle physically was administered by the IPA for the June 2013 through May 2017 period to meet certain requirements for purchased power related to the IEIMA. Marketing Company was a winning supplier in Ameren Illinois’ energy product procurement process. In February 2012, Marketing Company and Ameren Illinois entered into energy product agreements pursuant to which Marketing Company will sell and Ameren Illinois will purchase approximately 3,942,000 megawatthours at approximately $30 per megawatthour during the 12 months ending May 31, 2014, approximately 3,504,000 megawatthours at approximately $32 per megawatthour during the 12 months ending May 31, 2015, and approximately 1,317,600 megawatthours at approximately $34 per megawatthour during the 12 months ending May 31, 2016. The energy product agreements were based on around-the-clock prices.
Support Services Agreements
Ameren Services provides support services to its affiliates. The costs of support services, including wages, employee benefits, professional services, and other expenses, are based on, or are an allocation of, actual costs incurred. The shared services support agreement can be terminated with respect to a particular affiliate by the mutual agreement of Ameren Services and that affiliate or by either Ameren Services or that affiliate with 60 days notice before the end of a calendar year. Ameren has begun planning how it will to reduce, and ultimately eliminate AER's reliance on the support services agreement.
Gas Sales and Transportation Agreement
Under a gas transportation agreement, Genco acquires gas transportation service from Ameren Missouri. This agreement expires in February 2016.
Transmission Services Agreement
Under a transmission services agreement, Marketing Company acquires transmission services from Ameren Illinois and ATXI for certain retail and residential customers.
Collateral Postings
Under the terms of the Illinois power procurement agreements entered into through RFP processes administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Marketing Company, as a winning supplier in the RFP process, may be required to post collateral. As of December 31, 2012 and 2011, there were no collateral postings required of Marketing Company related to the Illinois power procurement agreements.
Marketing Company Sale of Trade Receivables to Ameren Illinois
        In accordance with the Illinois Public Utilities Act, Ameren Illinois is required to purchase alternative retail electric suppliers' receivables relating to Ameren Illinois' delivery service customers who elected to receive power supply from the alternative retail electric supplier. Beginning in June 2012, Marketing Company sold and Ameren Illinois purchased trade receivables relating to the power supply of residential customers using Marketing Company as their alternative retail electric supplier. Marketing Company has no continuing involvement with or control over the trade receivables after the sale is completed to Ameren Illinois, and neither company has any restrictions on the assets associated with these purchase and sale transactions. As of December 31, 2012, Ameren Illinois' payable to Marketing Company for the purchase of trade receivables totaled $5 million. For the year ended December 31, 2012, Ameren Illinois purchased $35 million of trade receivables from Marketing Company at a discount of less than $1 million. Marketing Company's receivable from Ameren Illinois as well as Ameren Illinois' payable to Marketing Company are eliminated in the consolidated Ameren Corporation's financial statements.
Intercompany Sales
In 2012, Genco completed the sale of land for cash proceeds of $2 million to ATXI. Genco recognized a $2 million gain from the sale. Under authoritative accounting guidance for rate-regulated entities, the gain was not eliminated upon consolidation.
Parent Company Guarantees
In the ordinary course of business, Ameren (parent) enters into various agreements providing financial assurance to third parties on behalf of its subsidiaries. Such agreements include, for example, guarantees and letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit and reducing the amount of cash collateral required to be posted. These agreements guarantee performance by Ameren's subsidiaries of obligations already existing on Ameren's consolidated balance sheet.
Upon the 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. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations for a period of up to 24 months after the closing. See Note 16 - Divestiture Transactions and Discontinued Operations.
At December 31, 2012, Ameren had a total of $354 million in guarantees outstanding, which included:
•
$189 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. The amounts above do not represent incremental consolidated Ameren obligations; rather, they represent Ameren parental guarantees of subsidiary obligations to third parties in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren's estimated exposure for obligations under transactions covered by these guarantees was $25 million at December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices.
•
$100 million associated with the guarantee agreement between Ameren and AERG entered into on March 28, 2012, relating to the put option agreement between Genco and AERG. On March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million from Ameren for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which was subject to FERC approval. In September 2013, Ameren paid Genco an additional $37 million based on the appraised value of these energy centers. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding the amended put option agreement and other transaction details.
•
$50 million guarantee to MISO for all of Ameren's subsidiaries who are MISO market participants. Ameren's estimated exposure for obligations under transactions covered by this guarantee was $32 million at December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices.
•
$15 million related to requirements for asset transactions, leasing, and other service agreements. At December 31, 2012, Ameren estimated it had no exposure to any of these guarantees.
Additionally, at December 31, 2012, Ameren had issued letters of credit totaling $9 million as credit support to certain subsidiaries.
The related party transactions discussed above, with the exception of Genco's land sale to ATXI and the parent company guarantees, are eliminated in Ameren's consolidated financial statements. Ameren will have continuing transactions with New AER after the divestiture is complete that will not be eliminated in Ameren's consolidated financial statements. The following table presents the impact of these related party transactions, primarily based on the agreements discussed above, for the years ended December 31, 2012, 2011, and 2010.
Agreement
Income Statement Line Item                    
 
  
 
Amount
Ameren Missouri and Genco gas
Operating Revenues
 
2012
 
$
1

transportation agreement
 
 
2011
 
1

 
 
 
2010
 
1

Ameren Illinois and ATXI transmission services agreement
Operating Revenues
 
2012
 
16

with Marketing Company
 
 
2011
 
11

 
 
 
2010
 
10

Total Operating Revenues
 
 
2012
 
$
17

 
 
 
2011
 
12

 
 
 
2010
 
11

Ameren Illinois power supply agreements
Purchased Power
 
2012
 
$
311

with Marketing Company
 
 
2011
 
232

 
 
 
2010
 
233

Ameren Illinois gas purchases from Genco
Gas Purchased for Resale
 
2012
 
$
—

 
 
 
2011
 
—

 
 
 
2010
 
1

Commitments And Contingencies
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, authorities, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.
See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 10 - Callaway Energy Center and Note 14 - Related Party Transactions with New AER in this report.
Callaway Energy Center
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at December 31, 2012. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.
Type and Source of Coverage
Maximum Coverages
 
Maximum Assessments
 
Public liability and nuclear worker liability:
 
 
 
 
American Nuclear Insurers
$
375


$
—

 
Pool participation
12,219

(a)  
118

(b)  
 
$
12,594

(c)  
$
118

 
Property damage:
 
 
 
 
Nuclear Electric Insurance Ltd.
$
2,750

(d)  
$
23

(e)  
Replacement power:
 
 
 
 
Nuclear Electric Insurance Ltd
$
490

(f)  
$
9

(e)  
Energy Risk Assurance Company
$
64

(g)  
$
—

 

(a)
Provided through mandatory participation in an industrywide retrospective premium assessment program.
(b)
Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c)
Limit of liability for each incident under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d)
Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(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)
Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(g)
Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 - Related Party Transactions with New AER for more information on this affiliate transaction.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. The next adjustment could occur during the fourth quarter of 2013. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by the Price-Anderson Act.
Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd’s policies, subject to an industrywide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s results of operations, financial position, or liquidity.
Leases
We lease various facilities, office equipment, plant equipment, and rail cars under capital and operating leases. The following table presents our lease obligations at December 31, 2012:
 
Total
 
2013
 
2014
 
2015
 
2016
 
2017
 
After 5 Years
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital lease payments(a)
$
588

 
$
32

 
$
32

 
$
33

 
$
33

 
$
33

 
$
425

Less amount representing interest
284

 
27

 
27

 
27

 
27

 
27

 
149

Present value of minimum capital lease payments
$
304

 
$
5

 
$
5

 
$
6

 
$
6

 
$
6

 
$
276

Operating leases(b)
138

 
19

 
14

 
14

 
14

 
14

 
63

Total lease obligations
$
442

 
$
24

 
$
19

 
$
20

 
$
20

 
$
20

 
$
339


(a)
See Properties under Part I, Item 2, and Note 3 - Property and Plant, Net of this report for additional information.
(b)
Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million for these items is included in the 2013 through 2017 columns, respectively.
Ameren recorded total rental expense, included in operating expenses, of $33 million, $36 million, and $41 million for the years ended December 31, 2012, 2011, and 2010, respectively.
Other Obligations
To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated fuel, purchased power, and other commitments at December 31, 2012. Ameren’s purchased power obligations include Ameren Missouri's 102-megawatt power purchase agreement with a wind farm operator that expires in 2024 and the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services at December 31, 2012, obligations related to IEIMA for Ameren Illinois, and obligations related to energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order for Ameren Missouri. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147 million over three years for energy efficiency programs. See Note 2 - Rate and Regulatory Matters for additional information about the IEIMA and MEEIA.
 
Coal
 
Natural
Gas
 
Nuclear
Fuel
 
Purchased
Power(a)
 
Methane
Gas
 
Other
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013
$
620

 
$
327

 
$
36

 
$
421

 
$
3

 
$
156

 
$
1,563

2014
625

 
249

 
89

 
309

 
3

 
159

 
1,434

2015
614

 
136

 
87

 
164

 
4

 
117

 
1,122

2016
644

 
54

 
95

 
78

 
4

 
62

 
937

2017
676

 
34

 
78

 
55

 
5

 
50

 
898

Thereafter
245

 
105

 
277

 
687

 
99

 
246

 
1,659

Total
$
3,424

 
$
905

 
$
662

 
$
1,714

 
$
118

 
$
790

 
$
7,613

(a)
The purchased power amounts includes Ameren Illinois' 20-year agreements for renewable energy credits that were entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.
Previously, Ameren Illinois entered into an agreement to purchase approximately 15.5 billion cubic feet of synthetic natural gas annually over a 10-year period beginning in 2016 for its natural gas customers. The agreement was entered into pursuant to an Illinois law, that became effective August 2, 2011. Ameren Illinois' obligations under the agreement were contingent on the counterparty reaching certain milestones during the project development and the construction of the plant that was to produce the synthetic natural gas. The counterparty failed to meet certain milestones during 2012 and, accordingly, the contract was terminated.
Environmental Matters
We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.
In addition to existing laws and regulations, including the Illinois MPS that applies to AER's energy centers in Illinois, the EPA is developing environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for fine particulates, SO2, and NO2 emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia in August 2012. Although many details of these future regulations are unknown, the combined effects on Ameren of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.
The estimates in the tables below contain all of the known capital costs to comply with existing environmental regulations, including the CAIR, and our assessment of the potential impacts of the EPA's proposed regulation for CCR and the finalized MATS as of December 31, 2012. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon a variety of factors including:
•
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;
•
new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;
•
additional rules governing air pollutant transport;
•
regulations 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 technology;
•
expected power prices;
•
variations in costs of material or labor; and
•
alternative compliance strategies or investment decisions.
Continuing Operations:
  
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.
Discontinued Operations:
  
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 the construction of two scrubbers at the Newton energy center.
(b)
Assumes the Merchant Generation facilities are owned by Ameren.
The decision to make pollution control equipment investments at AER depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in that year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. The table above includes Genco's estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for the construction of the two Newton energy center scrubbers. Based on the MPS variance granted by the Illinois Pollution Control Board in September 2012, AER is currently scheduled to complete the Newton scrubbers by the end of 2019. See additional information below regarding the MPS variance granted by the Illinois Pollution Control Board.
The following sections describe the more significant environmental rules that affect or could affect our operations.
Clean Air Act
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions.
In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, with further reductions in 2014. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court.
In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury and particulate matter that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016. Ameren Missouri's Labadie and Meramec energy centers requested and were granted extensions to comply with the MATS by April 2016.
Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to energy centers but could require reductions in SO2 and NOx emissions. Compliance with the finalized rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren is currently evaluating the new standard while the states of Missouri and Illinois develop their attainment plans.
In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard for ozone again in 2013. The states of Illinois and Missouri will be required to develop attainment plans to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control requirements for power plants by 2020. Ameren continue to assess the impacts of these new standards.
Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren Missouri's energy centers have historically burned, which allowed Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet, mercury control technology, and precipitator upgrades at multiple energy centers during the next 10 years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the MATS and other recently finalized or proposed EPA regulations.
In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO2 emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board's order also included the following provisions:
•
A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at Genco's Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019.
•
A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact Genco's ability to make the Meredosia energy center available for any parties that may be interested in repowering one of its units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.
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 terms as, AER’s variance related to 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 the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of AER.
Under the MPS, AER is required to reduce mercury and NOx emissions by 2015 and SO2 emissions by the end of 2019. The Illinois Pollution Control Board's September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NOx, and SO2. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco's Newton energy center. AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations and compliance technologies, among other factors.
Environmental compliance costs could be prohibitive at some of Ameren's, Ameren Missouri's and AER's energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.
Emission Allowances
The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations. The CAIR uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. Ameren expects to have adequate CAIR allowances for 2013 to avoid needing to make external purchases to comply with these programs.
Global Climate Change
State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. The enactment of a climate change law could result in a significant rise in rates for electricity and thereby household costs. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO2 as coal when burned to produce electricity. Therefore, climate change regulations could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economywide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.
In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.
Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule.
Separately, in March 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not affect any of Ameren's existing energy centers. Ameren anticipates this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2013. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and AER as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's results of operations, financial position, and liquidity.
Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including Ameren Missouri, Genco, and AERG, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. The case has been appealed to the appellate court.
The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, their impact on our coal-fired energy centers and our customers' costs is unknown, but they could result in significant increases in our capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.
NSR and Clean Air Litigation
The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.
Commencing in 2005, Genco received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at Genco's Newton energy center violated federal law. Genco believes its defenses to the allegations described in the Notice of Violation are meritorious. Ameren is unable to predict the outcome of this matter and whether the EPA will address this Notice of Violation administratively or through litigation.
Following the issuance of a Notice of Violation, in January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States District Court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for injunctive relief, including to require the installation of pollution control equipment, remain. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the Notices of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.
Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred.
Clean Water Act
In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to a specified level. The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in June 2013, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle energy centers at Ameren Missouri and AER with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and AER are currently evaluating the proposed rule, and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers.
In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in April 2013 and to finalize the rule in May 2014. We are unable at this time to predict the impact of this development.
Remediation
We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites.
As part of the transfer of generation assets by our rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003, Ameren Illinois’ predecessor companies contractually agreed to indemnify Genco and AERG for claims relating to pre-existing environmental conditions at the transferred sites. The plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The agreements will specify that all environmental liabilities associated with the Meredosia and Hutsonville energy centers will be assumed by Medina Valley. The agreements will also specify that Genco and AERG will no longer be indemnified by Ameren Illinois with respect to the environmental liabilities associated with Genco’s Newton and Coffeen energy centers and AERG’s E.D. Edwards and Duck Creek energy centers. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER.
As of December 31, 2012, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These are in various stages of investigation, evaluation, remediation and closure. Based on current estimated plans, Ameren and Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2018. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC.
As of December 31, 2012, Ameren Missouri has one remaining former MGP site for which remediation is scheduled. Remediation is complete at the other Ameren Missouri former MGP sites. Ameren Missouri does not currently have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with MGP sites from utility customers.
The following table presents, as of December 31, 2012, the estimated probable obligation to remediate these former MGP sites.
  
Estimate
 
Recorded
Liability(a)
 
Low
 
High
 
 
$
257

 
$
339

 
$
257

(a)
Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.
The scope and extent to which these sites are remediated has increased as remediation efforts continue. Considerable uncertainty remains in these estimates as many factors can influence the ultimate actual costs, including site specific unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances and site accessibility. The actual costs may vary substantially from these estimates.
Ameren Illinois utilized an off-site landfill, which Ameren Illinois did not own, in connection with its operation of the Coffeen energy center. While not currently mandated, Ameren Illinois may be required to perform certain remediation activities associated with that landfill. As of December 31, 2012, Ameren Illinois estimated the obligation related to the cleanup at $0.5 million to $6 million. Ameren recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of December 31, 2012, Ameren recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.
Ameren Missouri has responsibility for the investigation and potential cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of December 31, 2012, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the cleanup of this site, which was completed in 2005. Ameren Missouri anticipates that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup and it therefore has no recorded liability at December 31, 2012, for this site.
Ameren Missouri also has a federal agency mandate to complete an investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.
The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA and a record of decision is expected in 2013. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2. As of December 31, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren recorded a liability of $0.3 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri owned substation in St. Charles, Missouri. As of December 31, 2012, Ameren Missouri estimated the obligation related to the cleanup at $1.5 million to $2.3 million. Ameren recorded a liability of $1.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate.
Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity.
Ash Management
There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. We are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. We also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.
Pumped-storage Hydroelectric Facility Breach
In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.
Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of December 31, 2012, Ameren had an insurance receivable balance of $68 million. Ameren's results of operations, financial position and liquidity could be adversely affected if its remaining liability insurance claims are not paid by insurers.
In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In January 2011, the court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. Ameren Missouri appealed the January 2011 ruling to the United States Court of Appeals for the Eighth Circuit. In August 2012, the court of appeals remanded the case to the district court for consideration of whether Missouri law voids the alternative dispute resolution provision of the insurance policy.
Separately, in April 2012, Ameren Missouri sued a second insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In a November 2012 ruling, the United States District Court for the Eastern District of Missouri denied the insurer's motion to require arbitration. The insurer filed an appeal in the United States Court of Appeals for the Eighth Circuit.
Asbestos-related Litigation
Ameren has been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many as 272 parties named in some pending cases and as few as two in others. In the cases pending as of December 31, 2012, the average number of parties was 79.
The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers.
Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a condition to the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising or existing from activities prior to the transfer. The plant transfer agreement between Genco and Ameren Illinois and the plant transfer agreement between AERG and Ameren Illinois each will be amended pursuant to the transaction agreement in which Ameren agrees to divest New AER to IPH. The amended plant transfer agreements will provide that Ameren Illinois will continue to retain asbestos exposure-related liabilities for claims arising or existing from activities prior to the transfer of the ownership of the CIPS and CILCO energy centers to Genco and AERG. IPH will be responsible for any asbestos-related claims arising from activities that occur after IPH takes ownership of New AER. Any asbestos-related claims arising solely from activities post transfer of the energy centers from CIPS and CILCO to Genco and AERG, respectively, but prior to IPH taking ownership of New AER, of which there are currently none, will be retained by Ameren. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren's divestiture of New AER.
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31, 2012:
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Total(a)
4
 
74
 
96
 
121
(a)
Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
At December 31, 2012, Ameren had liabilities of $23 million recorded to represent its best estimate of its obligations related to asbestos claims.
Ameren Illinois has a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At December 31, 2012, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. The rider will permit recovery only from customers within IP’s historical service territory.
Ameren Illinois Municipal Taxes
Ameren Illinois received tax liability notices from the city of O'Fallon, Illinois relating to prior-period electric and natural gas municipal taxes. The city alleges that Ameren Illinois failed to collect prior-period taxes from more than 2,100 local resident addresses primarily in newly annexed areas for the period 2005 through 2010. Ameren Illinois is challenging the city's position on this matter. Ameren Illinois believes its defenses to the notices of tax liability are meritorious and will defend itself vigorously.  As of December 31, 2012, Ameren Illinois did not believe it was probable that the city of O'Fallon would prevail and therefore have not recorded a charge to earnings for a loss contingency related to this matter.  Should Ameren Illinois ultimately be found liable for these prior-period municipal taxes, the amount is estimated between $2 million and $4 million, including interest and penalties. In addition, at the end of 2012, the city of O'Fallon and six other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain local resident addresses. At this time, it is too early in Ameren Illinois' review of the additional notices to reasonably estimate any likelihood of loss.
Divestiture Transactions and Discontinued Operations (Notes)
DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS
DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS
Transaction Agreement with IPH
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for certain intercompany balances discussed below, (ii) all of the issued and outstanding equity interests in Medina Valley, which were distributed to Ameren in March 2013, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower energy centers, (iv) the obligations relating to Ameren's single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren's ownership of these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER.
Ameren will retain the pension and postretirement benefit obligations associated with current and former employees of AER that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. This obligation is reflected on Ameren’s consolidated balance sheet as “Pension and other postretirement benefits.” IPH will assume the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. The obligations to be assumed by IPH are estimated at $40 million at December 31, 2012. IPH will also acquire the estimated $15 million asset at December 31, 2012, relating to the overfunded status of one of EEI’s postretirement plans.
Ameren will retain Genco’s Meredosia and Hutsonville energy centers, which are no longer in operation and had an immaterial property and plant asset balance as of December 31, 2012. Ameren will also retain AROs associated with these energy centers, estimated at $26 million as of December 31, 2012. All other AROs associated with AER are expected to be assumed by either IPH or the third-party buyer of the Grand Tower energy center. Upon the transaction agreement closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from New AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its non-AER affiliates, on the other hand, will be either retained or cancelled by Ameren, without any cost or obligation to IPH or New AER and its subsidiaries. Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren, which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Cash collateral postings by AER and its subsidiaries with external parties, including postings related to exchange-traded contracts, at December 31, 2012, were $27 million.
Genco's $825 million in aggregate principal amount of senior notes will remain outstanding following the closing of the transaction agreement and will continue to be solely obligations of Genco. Pursuant to the transaction agreement, in addition to the cash paid to Genco for the Elgin, Gibson City, and Grand Tower energy center sale, Ameren will cause $85 million of cash to be retained at New AER.
As a condition to the transaction agreement, Genco exercised the amended put option agreement for the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Ameren expects a third-party sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers will be completed by the end of 2013.
Completion of the New AER sale to IPH was subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of the divestiture of New AER and Genco’s sale of the Elgin, Gibson City, and Grand Tower natural gas-fired energy centers to Medina Valley. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and Genco's sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. In addition, the FCC approval of the required license transfers was received in August 2013. Separately, as a condition to IPH’s obligation to complete the New AER transaction, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same 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 the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 15 - Commitments and Contingencies for additional information. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that AER will be operated in the ordinary course prior to the closing.
Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, subject to a 1 month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement.
Amended Put Option Agreement, Asset Purchase Agreement and Guaranty
See Note 14 - Related Party Transactions with New AER for additional information regarding the original put option agreement between Genco and AERG that was entered into on March 28, 2012.
Prior to entry into the transaction agreement with IPH as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. In connection with the amended put option agreement, Ameren's guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley. Pursuant to the amended put option agreement, Genco and Medina Valley entered into an asset purchase agreement, dated March 14, 2013.
The asset purchase agreement contains customary representations, warranties and covenants of Genco and Medina Valley. The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions.
A wholesale customer of Marketing Company has filed a lawsuit, in the United States District Court for the Central District of Illinois, against Ameren alleging that certain assets related to the amended put option agreement may not be sold without the customer’s consent, per the contract between the wholesale customer and Marketing Company. In addition, the lawsuit alleges that Genco and AERG failed to reflect a similar impairment of assets that was recorded by Ameren (parent) in the fourth quarter of 2012, which would have reduced the billings to the wholesale customer. Ameren believes its defenses to these allegations are meritorious and will defend itself vigorously.
Discontinued Operations Presentation
As of March 14, 2013, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation and, therefore, were classified separately in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. Ameren concluded that New AER and collectively the Elgin, Gibson City, and Grand Tower gas-fired energy centers are two separate disposal groups. Both disposal groups have been aggregated in the disclosures below. Each disposal group was measured at fair value on a nonrecurring basis with inputs that are classified as Level 3 within the fair value hierarchy.
Ameren will have continuing transactions with New AER after the divestiture is complete. Ameren Illinois has power supply agreements with Marketing Company, which are a result of the power procurement process in Illinois administered by the IPA as required by the Illinois Public Utilities Act. Ameren Illinois will continue to purchase power and purchase trade receivables as required by Illinois law, and Ameren will reflect these items as continuing operations after the divestiture occurs. Ameren Illinois and ATXI currently sell, and will continue to sell, transmission services to Marketing Company after the divestiture of New AER is completed. Also, 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 for all transactions entered into prior to the closing of such divestiture for up to 24 months after the closing. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH’s indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Also, within 120 days after closing, a working capital adjustment will be finalized, which may result in a cash payment from Ameren to New AER. Ameren has determined that the continuing cash flows generated by these arrangements are not significant and, accordingly, are not deemed direct cash flows of the divested business. Additionally, these arrangements do not provide Ameren the ability to significantly influence the operating results of New AER after the divestiture is complete. See Note 14 - Related Party Transactions with New AER for additional information regarding existing transactions between Ameren and New AER. Ameren does not expect to have significant continuing involvement with or material cash flows from the Elgin, Gibson City, and Grand Tower energy centers after their sale.
For a period of up to 12 months following the closing, Ameren will provide certain transitional services to IPH. Such services will be provided at no charge for 90 days, subject to a $5 million limit; thereafter, services will be provided at cost, except for certain services that may be applied to the $5 million limit to the extent such limit has not been reached by the end of the 90 days period. The transitional services may be provided for 6 months after the closing and can be extended by IPH on a month-to-month basis for up to an additional 6 months.
See Note 15 - Commitments and Contingencies for information regarding amendments to the plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois as well as other AER related contingencies.
Interest on Genco’s senior notes, which will continue to be solely obligations of Genco following the closing of the transaction agreement with IPH, are included in the “Interest charges” component within the discontinued operations line item in the consolidated statement of income (loss). Ameren did not allocate corporate interest to the disposal groups. Additionally, general corporate overhead expenses originally allocated to the disposal groups were classified as expenses of continuing operations.
The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the year ended December 31, 2012, 2011 and 2010:
 
Year ended
 
 
2012
 
2011
 
2010
 
Operating revenues
$
1,047

 
$
1,278

 
$
1,369

 
Operating expenses
(3,478
)
(a) 
(1,048
)
 
(1,578
)
(b) 
Operating income (loss)
(2,431
)
 
230

 
(209
)
 
Other income (loss)
—

 
1

 
2

 
Interest charges
(56
)
 
(64
)
 
(83
)
 
Income (loss) before income taxes
(2,487
)
 
167

 
(290
)
 
Income tax (expense) benefit
989

 
(65
)
 
(51
)
 
Income (loss) from discontinued operations, net of taxes
$
(1,498
)
 
$
102

 
$
(341
)
 
(a)
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. In addition, includes a noncash pretax asset impairment charge of $1.95 billion to reduce the carrying values of all the AER coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values, under held and used accounting guidance, as a result of the decision in December 2012 that Ameren intends to exit the Merchant Generation business.
(b)
Includes a noncash pretax goodwill impairment charge of $420 million representing all the goodwill assigned to Ameren's Merchant Generation reporting unit as a result of proposed and pending environmental regulations which were expected to result in a significant increase in capital and operations and maintenance expenditures for the energy centers held by AER. Also, includes a $36 million noncash pretax asset impairment charge to reduce the carrying value of the Medina Valley energy center to its estimated fair value and a noncash pretax intangible asset impairment charge of $68 million to reduce existing SO2 emission allowances to their estimated fair value.
Long-lived Asset Impairments
Ameren's Merchant Generation segment has experienced decreasing earnings and cash flows from operating activities over the past few years, including in 2012, as margins have declined principally as a result of weaker power prices. In addition, environmental regulations have resulted in significant investment requirements over the same time frame. During this period, Ameren has increasingly focused on allocating its capital resources to those opportunities that it believes offer the most attractive risk-adjusted return potential, and specifically focused on growing earnings from its rate-regulated operations through investment under constructive regulatory frameworks. Ameren has sought to have its Merchant Generation segment fund its operations internally and not rely on financing from Ameren. In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren's analysis of the current and projected future financial condition of its Merchant Generation segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation segment's reliance on Ameren's financial support and shared services support.
As a result of the December 2012 decision that Ameren intends to, and it is probable that it will, exit the Merchant Generation segment before the end of the Merchant Generation long-lived assets' previously estimated useful lives, Ameren determined that estimated undiscounted cash flows during the period in which it expects to continue to own certain energy centers would be insufficient to recover the carrying value of those energy centers. Accordingly, Ameren recorded a noncash pretax impairment charge of $1.95 billion in the fourth quarter of 2012 to reduce the carrying values of all of the Merchant Generation's coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values. The estimated undiscounted cash flows of the Joppa coal-fired energy center exceeded its carrying value; therefore, the Joppa coal-fired energy center was unimpaired.
In early 2012, the observable market price for power for delivery in that year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012. The sharp decline in the market price of power in early 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco's Newton energy center scrubber project, caused Merchant Generation to evaluate, during the first quarter of 2012, whether the carrying values of its coal-fired energy centers were recoverable. The carrying value of AERG's Duck Creek energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of that energy center to its estimated fair value during the first quarter of 2012.
During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused Ameren to evaluate if the carrying value of its Merchant Generation energy centers were recoverable. The Medina Valley energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, during 2010, Ameren recorded a noncash pretax asset impairment charges of $36 million to reduce the carrying value of the Medina Valley energy center to its estimated fair value. In 2012, Ameren sold the Medina Valley energy center.
Key assumptions used in the determination of estimated undiscounted cash flows of Ameren’s Merchant Generation segment’s long-lived assets tested for impairment included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and terminal year earnings multiples, were used to estimate the fair value of each energy center. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements. Impairment within the Merchant Generation business segment was assessed at the energy center level.
Goodwill Impairment
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Goodwill impairment testing is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, a second step is performed to measure the amount of impairment, if any. The second step of the goodwill impairment test compares the implied fair value of the reporting unit’s goodwill with the carrying amount of that goodwill. The implied fair value of goodwill is determined by allocating the estimated fair value of the reporting unit to the estimated fair value of its existing assets and liabilities. The unallocated portion of the estimated fair value of the reporting unit is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss equivalent to the difference is recorded as a reduction of goodwill and a charge to operating expense.
During the third quarter of 2010, we concluded that events had occurred and circumstances had changed which, when considered in the aggregate, indicated that it was more likely than not that the fair value of Ameren’s Merchant Generation reporting unit was less than its carrying value. Such events and circumstances included the sustained decline in market prices for electricity, industry market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted. In July 2010, the EPA issued the proposed CSAPR. The proposed CSAPR, along with other pending regulations, was expected to result in a significant increase in capital and operations and maintenance expenditures for Ameren’s Merchant Generation energy centers.
Ameren’s Merchant Generation reporting unit failed step one of the 2010 interim impairment test, as the reporting unit’s carrying value exceeded its estimated fair value. Therefore, in order to measure the goodwill impairment in step two, we estimated the implied fair value of Ameren’s Merchant Generation goodwill. We determined that the implied fair value of goodwill was less than the carrying amount of goodwill, indicating that Ameren’s Merchant Generation goodwill was impaired. Based on the results of step two of the impairment test, Ameren recorded a noncash impairment charge of $420 million, which represented all of the goodwill assigned to Ameren’s Merchant Generation reporting unit.
The fair value estimate of Ameren’s Merchant Generation reporting unit was based on a combination of the income approach, which considers discounted future cash flows, and the market approach, which considers market comparables within the electric generation industry. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year cash flows, and observable industry market multiples. We used our best estimates in making these evaluations. We considered various factors, including forward price projections for energy and fuel costs, environmental compliance costs, and operating costs. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.
Intangible Assets Impairment
Prior to 2010, Ameren’s Merchant Generation business expected to use its SO2 emission allowances for ongoing operations. In July 2010, the EPA issued the proposed CSAPR, which would have restricted the use of existing SO2 emission allowances. As a result, Merchant Generation no longer expected all of its SO2 emission allowances would be used in operations. Therefore, during 2010, Ameren recorded a $68 million pretax impairment charge to reduce the carrying value of Merchant Generation’s SO2 emission allowances to their estimated fair value.
In July 2011, the EPA issued CSAPR, which created new allowances for SO2 and NOx emissions and restricted the use of pre-existing SO2 and NOx allowances to the acid rain program and to the NOx budget trading program, respectively. As a result, observable market prices for existing emission allowances declined materially. Consequently, Ameren recorded a noncash pretax impairment charge of $2 million in 2011 relating to Merchant Generation’s emission allowances.
The fair value of the SO2 and NOx emission allowances were based on observable and unobservable inputs, which were classified as Level 3 inputs for fair value measurements.
The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at December 31, 2012 and 2011:
 
December 31, 2012
 
December 31, 2011
Current assets of discontinued operations
 
 
 
Cash and cash equivalents
$
25

 
$
7

Accounts receivable and unbilled revenue
102

 
108

Materials and supplies
134

 
162

Mark-to-market derivative assets
102

 
65

Property and plant, net
748

 
3,279

Accumulated deferred income taxes, net
385

 
—

Other assets
104

 
97

Total current assets of discontinued operations
$
1,600

 
$
3,718

Current liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
$
133

 
$
134

Mark-to-market derivative liabilities
63

 
39

Long-term debt, net
824

 
824

Accumulated deferred income taxes, net
—

 
583

Asset retirement obligations
78

 
64

Pension and other postretirement benefits
40

 
92

Other liabilities
28

 
26

Total current liabilities of discontinued operations
$
1,166

 
$
1,762

Accumulated other comprehensive income (loss)(a)
$
19

 
$
(31
)
Noncontrolling interest(b)
$
8

 
$
7

(a)
Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s December 31, 2012 and 2011, consolidated balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s consolidated balance sheet either before or at the closing of the New AER divestiture.
(b)
The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s December 31, 2012 and 2011, consolidated balance sheets. This noncontrolling interest will be removed from Ameren’s consolidated balance sheet at the closing of the New AER divestiture.
2013 Impairments
Beginning on March 14, 2013, the New AER disposal group and the Elgin, Gibson City, and Grand Tower energy center disposal group both met the discontinued operations criteria. As a result, Ameren evaluated whether any impairment existed by comparing each disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. Ameren recorded a cumulative pretax charge to earnings of $168 million for the six months ended June 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. Ameren estimated the impairment loss of the disposal group based on the estimated fair value pursuant to the terms of the transaction agreement with IPH, using information currently available, and assuming an expected fourth quarter 2013 closing. Actual operating results, derivative market values, capital expenditures and other items will impact the ultimate loss recognized to reduce the carrying value of the New AER disposal group to its actual fair value less cost to sell, which will be recorded in discontinued operations after all of the information becomes available. In addition, any curtailment gain related to Ameren's pension and postretirement plans will be recorded when the related employees terminate employment with Ameren. The ultimate impairment loss may differ materially from the estimated loss recorded as of June 30, 2013. In December 2012, as discussed above, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying value of AER’s energy centers, including the Elgin, Gibson City, and Grand Tower energy centers, to their estimated fair values under the accounting guidance for held and used assets. An immaterial impairment was recorded by Ameren for the three gas-fired energy centers during the six months ended June 30, 2013, as the December 2012 held and used asset impairment charge reduced these energy centers’ disposal group carrying value to their estimated fair value of $133 million.
Ameren adjusted accumulated deferred income taxes on its consolidated balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, during 2013, when it became apparent that the temporary difference would reverse. Ameren recorded a discontinued operations deferred tax expense of $97 million, which was partially offset by the expected tax benefits of $69 million related to the 2013 impairment charge, during the six months ended June 30, 2013. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon taxable losses utilized by the disposal group through the closing and the resolution of tax matters under audit, including the adoption of recently issued guidance from the IRS related to tangible property repairs and other matters. As a result, tax expense and benefits realized in discontinued operations may differ materially from those recorded as of June 30, 2013.
Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City, and Grand Tower energy centers’ disposal group each met the criteria for held for sale presentation, Ameren suspended recording depreciation on these assets in March 2013.
Genco Indenture Provisions
Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the 12 months ended and as of December 31, 2012:
  
Required
Ratio
Actual
Ratio
Interest coverage ratio- restricted payment (a)
≥1.75
2.6

Interest coverage ratio- additional indebtedness (b)
≥2.50
2.6

Debt-to-capital ratio- additional indebtedness (b)
≤60%
44
%
(a)
As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
(b)
Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.
Genco’s debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.
As shown in the table above, under the provisions of Genco’s indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than 2.5 or its debt-to-capital ratio is greater than 60%. Beginning in the first quarter of 2013, Genco’s interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and Genco expects the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external third-party sources is restricted. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control. If a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. As stated above, the transaction agreement requires Ameren to operate New AER, including Genco, in the ordinary course prior to the closing.
Genco's indenture includes restrictions that prohibit it from making dividend payments on its common stock. Specifically, Genco cannot pay dividends on its common stock unless the company’s actual interest coverage ratio for the most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on projections as of December 31, 2012, of Genco's operating results and cash flows in 2013 and 2014, we did not believe that Genco would achieve the minimum interest coverage ratio necessary to pay dividends on its common stock for each of the subsequent four six-month periods ending June 30, 2013, December 31, 2013, June 30, 2014, or December 31, 2014. As a result, Genco was restricted from paying dividends on its common stock as of December 31, 2012, and we expect Genco will be unable to pay dividends on its common stock in 2013, 2014, and 2015.
Illinois Sales and Use Tax Exemptions and Credits
In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. As of December 31, 2012, Ameren did not believe that it was probable that the state of Illinois will prevail and therefore had not recorded a charge to earnings for the loss contingency. During second quarter of 2013, Ameren and the Department of Revenue resolved the tax liabilities for all open periods related to this issue with a payment of $7 million by Genco, including EEI, and AERG to the Illinois Department of Revenue.
Impairment and Other Charges
IMPAIRMENT AND OTHER CHARGES
MPAIRMENT AND OTHER CHARGES
The following table summarizes the pretax charges recorded in the consolidated statement of income (loss) as “Impairment and other charges” for the years ended December 31, 2012, 2011, and 2010:
 
2012
2011
2010
Long-Lived Assets and Related Charges
$
—

$
123

$
64


The impairment charges did not result in a violation of any Ameren or Ameren subsidiary debt covenants or counterparty agreements. Each of the charges is discussed below.
The Ameren Companies evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, the Ameren Companies recognize an impairment charge equal to the amount of the carrying value of the assets that exceeds its estimated fair value.
In December 2011, Genco ceased operations of its Meredosia and Hutsonville energy centers. As a result, Ameren recorded a noncash pretax asset impairment charge of $26 million to reduce the carrying value of the Meredosia and Hutsonville energy centers to their estimated fair values, a $4 million impairment of materials and supplies, and $4 million for severance costs. See Note 1 - Summary of Significant Accounting Policies for further information regarding severance costs.
During 2011, the MoPSC issued an electric rate order that disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of the amount recovered from property insurance. Consequently, Ameren recorded a pretax charge to earnings of $89 million.
During the third quarter of 2010, the aggregate impact of a sustained decline in market prices for electricity, industry transaction market multiples became observable at lower levels than previously estimated, and potentially more stringent environmental regulations being enacted caused Ameren to evaluate if the carrying value of its Merchant Generation energy centers were recoverable. The Meredosia energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, during 2010, Ameren recorded a noncash pretax asset impairment charge of $64 million to reduce the carrying value of the Meredosia energy center to its estimated fair value.
Key assumptions used in the determination of estimated undiscounted cash flows of Ameren’s long-lived assets tested for impairment included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate and terminal year earnings multiples, were used to estimate the fair value of each energy center. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and the market approach, which considers market multiples for similar assets within the electric generation industry. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements. Impairment within the Merchant Generation business was assessed at the energy center level. Ameren does not expect to incur material future cash expenditures as a result of these impairments.
Segment Information
SEGMENT INFORMATION
SEGMENT INFORMATION
Ameren has three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment includes all the operations of Ameren Missouri’s business as described in Note 1 - Summary of Significant Accounting Policies. The Ameren Illinois segment includes all of the operations of Ameren Illinois' business as described in Note 1 - Summary of Significant Accounting Policies. The Merchant Generation segment for Ameren consisted primarily of the operations or activities of AER, including Genco, EEI, AERG, and Marketing Company. Ameren is divesting its Merchant Generation segment and therefore has excluded that segment's information below. See Note 16 - Divestiture Transactions and Discontinued Operations for information regarding the Merchant Generation segment. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI. The Other category also includes activities previously included in the Merchant Generation segment that will be retained by Ameren after the divestiture of New AER and the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers are complete. See Note 16 - Divestiture Transactions and Discontinued Operations for information regarding the assets and liabilities to be retained by Ameren after the divestitures.
The following table presents information about the reported revenues and specified items reflected in net income attributable to Ameren Corporation from continuing operations for the years ended December 31, 2012, 2011, and 2010, and total assets as of December 31, 2012, 2011, and 2010.
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Other
 
Intersegment
Eliminations
 
Consolidated
 
2012
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,252

 
$
2,524

 
$
5

 
$
—

 
$
5,781

 
Intersegment revenues
20

 
1

 
3

 
(24
)
 
—

 
Depreciation and amortization
440

 
221

 
6

 
—

 
667

 
Interest and dividend income
32

 
—

 
—

 
—

 
32

 
Interest charges
223

 
129

 
39

 
—

 
391

 
Income taxes (benefit)
252

 
94

 
(37
)
 
—

 
309

 
Net income (loss) attributable to Ameren Corporation from continuing operations
416

 
141

 
(39
)
 
—

 
518

 
Capital expenditures
595

 
442

 
26

 
—

 
1,063

 
Total assets
13,043

 
7,282

 
1,228

 
(934
)
 
20,619

(a) 
2011
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,360

 
$
2,784

 
$
83

 
$
—

 
$
6,227

 
Intersegment revenues
23

 
3

 
3

 
(29
)
 
—

 
Depreciation and amortization
408

 
215

 
23

 
—

 
646

 
Interest and dividend income
30

 
1

 
—

 
—

 
31

 
Interest charges
209

 
136

 
42

 
—

 
387

 
Income taxes (benefit)
161

 
127

 
(43
)
 
—

 
245

 
Net income (loss) attributable to Ameren Corporation from continuing operations
287

 
193

 
(62
)
 
—

 
418

 
Capital expenditures
550

 
351

 
(20
)
(b) 
—

 
881

 
Total assets
12,757

 
7,213

 
1,211

 
(1,176
)
 
20,005

(a) 
2010
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,180

 
$
3,012

 
$
77

 
$
—

 
$
6,269

 
Intersegment revenues
17

 
2

 
—

 
(19
)
 
—

 
Depreciation and amortization
382

 
210

 
35

 
—

 
627

 
Interest and dividend income
31

 
1

 
—

 
—

 
32

 
Interest charges
213

 
143

 
59

 
—

 
415

 
Income taxes (benefit)
199

 
137

 
(62
)
 
—

 
274

 
Net income (loss) attributable to Ameren Corporation from continuing operations
364

 
208

 
(89
)
 
—

 
483

 
Capital expenditures
624

 
281

 
36

 
—

 
941

 
Total assets
12,504

 
7,406

 
1,354

 
(1,541
)
 
19,723

(a) 
(a)
Excludes "Current assets for discontinued operations." See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.
(b)
Includes the elimination of intercompany transfers.
Selected Quarterly Information
SELECTED QUARTERLY INFORMATION
SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)
 
 
2012
 
 
2011
Quarter ended (a)
 
March 31
 
June 30
 
September 30
 
December 31
 
 
March 31
 
June 30
 
September 30
 
December 31
Operating Revenues
 
$
1,412

 
$
1,402

 
$
1,709

 
$
1,258

 
 
$
1,597

 
$
1,458

 
$
1,876

 
$
1,296

Operating Income (b)
 
158

 
344

 
578

 
111

 
 
156

 
270

 
494

 
91

Net Income (Loss)
 
(403
)
 
210

 
374

 
(1,155
)
 
 
74

 
139

 
287

 
26

Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations
 
$
37

 
$
161

 
$
305

 
$
15

 
 
$
38

 
$
116

 
$
265

 
$
(1
)
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations (c)
 
(440
)
 
50

 
69

 
(1,171
)
 
 
33

 
22

 
20

 
26

Net Income (Loss) Attributable to Ameren Corporation
 
$
(403
)
 
$
211

 
$
374

 
$
(1,156
)
 
 
$
71

 
$
138

 
$
285

 
$
25

Earnings (Loss) per Common Share - Basic and Diluted - Continuing Operations
 
$
0.15

 
$
0.66

 
$
1.26

 
$
0.06

 
 
$
0.16

 
$
0.48

 
$
1.10

 
$
(0.01
)
Earnings (Loss) per Common Share - Basic and Diluted - Discontinued Operations
 
(1.81
)
 
0.21

 
0.28

 
(4.82
)
 
 
0.13

 
0.09

 
0.08

 
0.11

Earnings (Loss) per Common Share - Basic and Diluted
 
$
(1.66
)
 
$
0.87

 
$
1.54

 
$
(4.76
)
 
 
$
0.29

 
$
0.57

 
$
1.18

 
$
0.10

(a)
The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding and changes in the number of weighted-average shares outstanding each period.
(b)
Includes pretax "Impairment and other charges" of $123 million recorded to continuing operations during the year ended December 31, 2011. See Note 17 - Impairment and Other Charges for additional information.
(c)
Includes a pretax asset impairment charge of $2.578 billion recorded to discontinued operations during the year ended December 31, 2012. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.
During preparation of the 2012 annual statement of cash flows, errors were identified in Ameren's 2012 interim statement of cash flows. The errors, which were $14 million, $26 million, and $49 million through the year-to-date first, second, and third quarters of 2012, respectively, are not considered material. The errors related to the classification of certain activity from the nuclear decommissioning trust fund and increased operating cash flows and reduced investing cash flows for each of these year-to-date periods. The 2012 interim statement of cash flows will be revised to correct for these errors in the Ameren 2013 Form 10-Q filings.
Schedule I - Condensed Financial Information Of Parent
Condensed Financial Information Of Parent
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(In millions)
2012
 
2011
 
2010
Operating revenues
$
—

 
$
—

 
$
—

Impairment and other charges
—

 
—

 
—

Operating expenses
17

 
13

 
19

Operating loss
(17
)
 
(13
)
 
(19
)
Equity in earnings of subsidiaries
548

 
451

 
525

Interest income from affiliates
3

 
5

 
8

Miscellaneous expense
4

 
4

 
3

Interest charges
39

 
41

 
56

Income tax (benefit)
(27
)
 
(20
)
 
(28
)
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations
518

 
418

 
483

Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations
(1,492
)
 
101

 
(344
)
Net income (Loss) Attributable to Ameren Corporation
$
(974
)
 
$
519

 
$
139

 
 
 
 
 
 
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations
$
518

 
$
418

 
$
483

Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $6, $14, and $(7), respectively
(8
)
 
(19
)
 
10

Comprehensive Income from Continuing Operations
$
510

 
$
399

 
$
493

Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations
$
(1,492
)
 
$
101

 
$
(344
)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes
$
50

 
$
(14
)
 
$
(14
)
Comprehensive Income (Loss) from Discontinued Operations
$
(1,442
)
 
$
87

 
$
(358
)
Comprehensive Income (Loss) Attributable to Ameren Corporation
$
(932
)
 
$
486

 
$
135

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED BALANCE SHEET
(In millions)
December 31, 2012
 
December 31, 2011
Assets:
 
 
 
Cash and cash equivalents
$
23

 
$
3

Advances to money pool
316

 
340

Accounts and notes receivable - affiliates
31

 
57

Other current assets
49

 
—

Total current assets
419

 
400

Investments in subsidiaries - continuing operations
6,288

 
6,327

Investments in subsidiaries - discontinued operations
(326
)
 
1,155

Note receivable - affiliates
462

 
425

Other non-current assets
320

 
333

Total assets
$
7,163

 
$
8,640

Liabilities and Stockholders’ Equity:
 
 
 
Short-term debt
$
—

 
$
148

Accounts payable - affiliates
10

 
13

Other current liabilities
33

 
62

Total current liabilities
43

 
223

Long-term debt
424

 
424

Other deferred credits and liabilities
80

 
74

Total liabilities
547

 
721

Commitments and Contingencies
 
 
 
Stockholders’ Equity:
 
 
 
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6
2

 
2

Other paid-in capital, principally premium on common stock
5,616

 
5,598

Retained earnings
1,006

 
2,369

Accumulated other comprehensive income (loss)
(8
)
 
(50
)
Total stockholders’ equity
6,616

 
7,919

Total liabilities and stockholders’ equity
$
7,163

 
$
8,640


SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
AMEREN CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(In millions)
2012
 
2011
 
2010
Net cash flows provided by operating activities
$
532

 
$
804

 
$
241

Cash flows from investing activities:
 
 
 
 
 
Money pool advances, net
24

 
(276
)
 
18

Notes receivable - affiliates, net
(20
)
 
358

 
242

Investments in subsidiaries
(2
)
 
(94
)
 
(13
)
Distributions from subsidiaries
21

 
3

 
1

Other
(5
)
 
(5
)
 
—

Net cash flows provided by (used in) investing activities
18

 
(14
)
 
248

Cash flows from financing activities:
 
 
 
 
 
Dividends on common stock
(382
)
 
(375
)
 
(368
)
Short-term debt and credit facility borrowings, net
(148
)
 
(481
)
 
(221
)
Issuances of common stock
—

 
65

 
80

Net cash flows used in financing activities
(530
)
 
(791
)
 
(509
)
Net change in cash and cash equivalents
$
20

 
$
(1
)
 
$
(20
)
Cash and cash equivalents at beginning of year
3

 
4

 
24

Cash and cash equivalents at the end of year
$
23

 
$
3

 
$
4

Cash dividends received from consolidated subsidiaries
$
610

 
$
730

 
$
368

 
 
 
 
 
 
Noncash financing activity – dividends on common stock
$
(7
)
 
$
—

 
$
—

BASIS OF PRESENTATION
Ameren Corporation (parent company only) is a public utility holding company that conducts substantially all of its business operations through its subsidiaries. As specified in Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K, there are restrictions on Ameren Corporation’s (parent company only) ability to obtain funds from certain of its subsidiaries through dividends, loans or advances. In accordance with authoritative accounting guidance, Ameren Corporation (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included within the combined notes under Exhibit 99.4, Item 8, of this Current Report on Form 8-K.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren's entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which was subject to FERC approval. Ameren expects a third-party sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers will be completed by the end of 2013. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this current Report on Form 8-K for additional information regarding these divestitures. As a result of the transaction agreement with IPH and Ameren's plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation. Therefore, Ameren has segregated New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers and presented them separately as discontinued operations for all periods presented on the Condensed Statement of Income (Loss) and Comprehensive Income (Loss) and Condensed Balance sheet. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding that presentation.
SHORT-TERM DEBT AND LIQUIDITY
See Note 4 - Short-term Debt and Liquidity under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a description and details of short-term debt and liquidity needs of Ameren Corporation (parent company only).
LONG-TERM OBLIGATIONS
See Note 5 - Long-term Debt and Equity Financings under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for a description and details of long-term obligations of Ameren Corporation (parent company only).
COMMITMENTS AND CONTINGENCIES
See Note 14 - Related Party Transactions with New AER and Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on form 8-K for a description of all material contingencies and guarantees outstanding of Ameren Corporation (parent company only).
IMPAIRMENT

In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren's analysis of the current and projected future financial condition of its Merchant Generation segment and its conclusion that this segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation segment's reliance on Ameren's financial support and shared services support.
As a result of the announcement that Ameren intends to exit the Merchant Generation segment before the end of the Merchant Generation's long-lived assets' previously estimated useful lives, Ameren determined that estimated undiscounted cash flows during the period in which it expects to continue to own certain energy centers would be insufficient to recover the carrying value of those energy centers. Accordingly, in the fourth quarter of 2012, Ameren Corporation (parent company only) recorded a noncash pretax impairment charge of $1.88 billion to reduce its investment in certain of the Merchant Generation segment's coal and natural gas-fired energy centers to their estimated fair values. This charge was included within "Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations" (parent company only) in the Condensed Statement of Income (Loss) and Comprehensive Income (Loss) for the year ended December 31, 2012.
Schedule II - Valuation And Qualifying Accounts
Valuation And Qualifying Accounts
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
(in millions)
 
 
 
 
 
 
 
 
 
Column A
Column B
 
Column C
 
Column D
 
Column E
Description
Balance at
Beginning
of Period
 
(1)
Charged to Costs
and Expenses
 
(2)
Charged to Other
Accounts(a)
 
Deductions(b)
 
Balance at End
of Period
Ameren:
 
 
 
 
 
 
 
 
 
Deducted from assets - allowance for doubtful accounts:
 
 
 
 
 
 
 
 
 
2012
$
20

 
$
30

 
$
2

 
$
35

 
$
17

2011
22

 
41

 
—

 
43

 
20

2010
24

 
32

 
—

 
34

 
22

Deferred tax valuation allowance:
 
 
 
 
 
 
 
 
 
2012
$
1

 
$
1

 
$
—

 
$
—

 
$
2

2011
1

 
—

 
—

 
—

 
1

2010
—

 
1

 
—

 
—

 
1

(a)
Uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers as required by the Illinois Public Utility Act.
(b)
Uncollectible accounts charged off, less recoveries.
Summary Of Significant Accounting Policies (Policy)
General 
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses. Dividends on Ameren’s common stock and the payment of other expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.
•
Union Electric Company, or Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Ameren Missouri was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri. This area has an estimated population of 2.8 million and includes the Greater St. Louis area. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.
•
Ameren Illinois Company, or Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois was created by the merger of CILCO and IP with and into CIPS. CIPS was incorporated in Illinois in 1923 and is successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to portions of central and southern Illinois having an estimated population of 3.1 million in an area of 40,000 square miles. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 806,000 customers.
•
AER consists of non-rate-regulated operations, including Genco, AERG, Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding the divestiture.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services.
In December 2012, Ameren determined that it intends to, and it is probable that it will, exit its Merchant Generation business before the end of the previously estimated useful lives of that business's long-lived assets. This determination resulted from Ameren’s analysis of the current and projected future financial condition of its Merchant Generation business segment, including the need to fund Genco debt maturities beginning in 2018, and its conclusion that this business segment is no longer a core component of its future business strategy. In consideration of this determination, Ameren has begun planning to reduce, and ultimately eliminate, the Merchant Generation business segment’s, including Genco's, reliance on Ameren’s financial support and shared services support. Furthermore, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying values of the Merchant Generation energy centers, except for the Joppa coal-fired energy center, to their estimated fair values. See Note 16 - Divestiture Transactions and Discontinued Operations.
On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH, which Ameren expects will occur in the fourth quarter of 2013. Immediately prior to Ameren's entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which was subject to FERC approval. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH and Genco's sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Ameren expects a third-party sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers will be completed by the end of 2013. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding these divestitures. As a result of the transaction agreement with IPH and Ameren's plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation beginning on March 14, 2013. Therefore, Ameren has segregated New AER's and the Elgin, Gibson City, and Grand Tower gas-fired energy centers' operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise noted, these notes to the financial statements have been revised to exclude discontinued operations for all periods presented. All other information herein remains unchanged. The information contained herein does not modify or update the disclosures contained in Ameren's Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 1, 2013, in any way, nor does it reflect any subsequent information or events, other than as required to reflect the results of the discontinued operations presentation described above. Information presented for the Ameren Missouri and Ameren Illinois registrants also remains unchanged. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation.
Consolidation 
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates.
Public Utilities 
Regulation
Certain Ameren subsidiaries are regulated by the MoPSC, the ICC, and FERC. In accordance with authoritative accounting guidance regarding accounting for the effects of certain types of regulation, Ameren Missouri and Ameren Illinois defer certain costs as assets pursuant to actions of rate regulators or because of expectations that the companies will be able to recover such costs in rates charged to customers. Ameren Missouri and Ameren Illinois also defer certain amounts as liabilities pursuant to actions of rate regulators or based on the expectation that such amounts will be returned to customers in future rates. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. In addition to the cost recovery mechanisms discussed in the Purchased Gas, Power and Fuel Rate-adjustment Mechanisms section below, Ameren Missouri and Ameren Illinois have approvals from regulators to use other cost recovery mechanisms. Ameren Missouri has a vegetation management and infrastructure inspection cost tracker, pension and postretirement benefit cost tracker, uncertain tax positions tracker, renewable energy standards cost tracker, and, starting in 2013, a storm restoration cost tracker and the MEEIA energy efficiency cost recovery mechanisms. Ameren Illinois has an environmental cost rider, asbestos-related litigation rider, energy efficiency rider, and a bad debt rider. See Note 2 - Rate and Regulatory Matters for additional information on regulatory assets and liabilities. In addition, other costs that Ameren Missouri and Ameren Illinois expect to recover from customers are recorded as construction work in progress and property and plant, net.
Environmental Costs
Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.
Investments
Ameren evaluates for impairment the investments held in Ameren Missouri's nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which Ameren believes would be recovered in electric rates paid by its customers. Accordingly, Ameren recognizes a regulatory asset on its consolidated balance sheet for losses on investments held in the nuclear decommissioning trust fund.
Purchased Gas, Power and Fuel Rate-adjustment Mechanisms
Ameren Missouri and Ameren Illinois have various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas and electric fuel and purchased power costs. See Note 2 - Rate and Regulatory Matters for the regulatory assets and liabilities recorded at December 31, 2012, and 2011, related to the rate-adjustment mechanisms discussed below.
In Ameren Missouri’s and Ameren Illinois’ retail natural gas utility jurisdictions, changes in natural gas costs are reflected in billings to their natural gas utility customers through PGA clauses. The differences between actual natural gas costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to natural gas utility customers in a subsequent period.
In Ameren Illinois’ retail electric utility jurisdictions, changes in purchased power costs and transmission service cost are reflected in billings to their electric utility customers through pass-through rate-adjustment clauses. The differences between actual purchased power and transmission service costs and costs billed to customers in a given period are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to electric utility customers in a subsequent period.
Ameren Missouri has a FAC that allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel, certain fuel additives, emission allowances, purchased power costs, transmission costs, and MISO costs and revenues, net of off-system revenues, greater or less than the amount set in base rates without a traditional rate proceeding, subject to MoPSC prudency review. The differences between the cost of fuel incurred and the cost of fuel recovered from Ameren Missouri customers' base rates are deferred as regulatory assets or liabilities. The deferred amounts are either billed or refunded to Ameren Missouri’s electric utility customers in a subsequent period. The MoPSC's December 2012 electric rate order changed the FAC to include activated carbon, limestone and urea costs, along with transmission revenues starting in 2013.
Accounting for MISO Transactions
MISO-related purchase and sale transactions are recorded by Ameren using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. We record net purchases in a single hour in “Operating Expenses - Purchased power” and net sales in a single hour in “Operating Revenues - Electric” in our statements of income (loss). On occasion, prior-period transactions will be resettled outside the routine settlement process because of a change in MISO’s tariff or a material interpretation thereof. In these cases, the Ameren Companies recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated, and the Ameren Companies recognize revenues once the resettlement amount is received.
Cash and Cash Equivalents 
Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.
Allowance for Doubtful Accounts Receivable 
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated loss factors to various classes of outstanding receivables, including unbilled revenue. The loss factors used to estimate uncollectible accounts are based upon both historical collections experience and management’s best estimate of future collections success given the existing and anticipated future collections environment. Ameren Illinois has a rate mechanism that adjusts rates for bad debt expense above or below those being collected in rates.
Materials and Supplies 
Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials and supplies are capitalized as inventory when purchased and then expensed or capitalized as plant assets when installed, as appropriate.
Property and Plant 
We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, as discussed specifically below, is also capitalized as a cost of our rate-regulated assets. Maintenance expenditures, including nuclear refueling and maintenance outages, are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage values, are charged to accumulated depreciation. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 - Property and Plant, Net, for additional information.
Depreciation
Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis to the cost basis of such property.
Allowance for Funds Used During Construction 
In our rate-regulated operations, we capitalize the allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, as is the utility industry's accounting practice. Allowance for funds used during construction does not represent a current source of cash funds. This accounting practice offsets the effect on earnings of the cost of financing during construction, and it treats such financing costs in the same manner as construction charges for labor and materials.
Under accepted ratemaking practice, cash recovery of allowance for funds used during construction and other construction costs occurs when completed projects are placed in service and reflected in customer rates.
Goodwill and Intangible Assets 
Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of December 31, 2012, Ameren’s goodwill related to the acquisitions of IP in 2004 and of CILCORP in 2003.
Ameren has three reporting units, which also represent Ameren’s reportable segments. Ameren's reporting units are Ameren Missouri, Ameren Illinois, and Merchant Generation. Ameren’s reporting units have been defined and goodwill has been evaluated at the operating segment level in accordance with authoritative accounting guidance. Our reporting units represent businesses for which discrete financial information is available and reviewed regularly by management. All of Ameren's goodwill at December 31, 2012, and 2011 has been assigned to the Ameren Illinois reporting unit.
We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Ameren applied a qualitative goodwill evaluation model for its annual goodwill impairment test conducted as of October 31, 2012. Based on the results of Ameren’s qualitative assessment, Ameren believes it was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value as of October 31, 2012, indicating no impairment of Ameren’s goodwill. The following factors, not meant to be all-inclusive, were considered by Ameren when assessing whether it was more likely than not that the fair value of the Ameren Illinois reporting unit exceeded its carrying value for the October 31, 2012, test:
•
Macroeconomic conditions, including those conditions within Ameren Illinois’ service territory;
•
Pending rate case outcomes and future rate case outcomes;
•
Changes in laws and potential law changes;
•
Observable industry market multiples;
•
Achievement of IEIMA performance metrics and the yield of the 30-year United States treasury bonds; and
•
Actual and forecasted financial performance.
The goodwill assigned to the Ameren Illinois reporting unit on Ameren's December 31, 2012 consolidated balance sheet had no accumulated goodwill impairment losses. Ameren will continue to monitor the actual and forecasted operating results, cash flows, market capitalization, and observable industry market multiples of the Ameren Illinois reporting unit for signs of possible declines in estimated fair value and potential goodwill impairment.
Intangible Assets. Ameren classifies emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At December 31, 2012, Ameren’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s renewable energy credits was $14 million and $7 million at December 31, 2012, and 2011, respectively.
Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations.
Impairment of Long-lived Assets 
We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the book value exceeds its fair value less cost to sell.
Unamortized Debt Discount, Premium, And Expense 
Discount, premium, and expense associated with long-term debt are amortized over the lives of the related issues.
Revenue 
The Ameren Companies record operating revenue for electric or natural gas service when it is delivered to customers. We accrue an estimate of electric and natural gas revenues for service rendered but unbilled at the end of each accounting period.
Beginning in 2012, Ameren Illinois elected to participate in performance-based formula ratemaking framework pursuant to the IEIMA. The IEIMA provides for an annual reconciliation of Ameren Illinois' electric distribution revenue requirement. As of each balance sheet date, Ameren Illinois records its best estimate of the electric distribution revenue impact resulting from the reconciliation of the revenue requirement necessary to reflect the actual costs incurred for that year with the revenue requirement that was in effect for that year. If the current year's revenue requirement is greater than the revenue requirement customer rates were based upon, an increase to electric operating revenues with an offset to a regulatory asset is recorded to reflect the expected recovery of those additional costs from customers within the next two years. If the current year's revenue requirement is less than the revenue requirement customer rates were based upon, a reduction to electric operating revenues with an offset to a regulatory liability is recorded to reflect the expected refund to customers within the next two years. See Note 2 - Rate and Regulatory Matters for information regarding Ameren Illinois' revenue requirement reconciliation pursuant to the IEIMA.
Beginning in 2013, Ameren Illinois will record the impact of a revenue requirement reconciliation for its electric transmission jurisdiction, pursuant to FERC-approved rate treatment.
Cost Of Sales 
Ameren Missouri’s cost of nuclear fuel is capitalized and then amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost is based on net kilowatthours generated and sold, and that cost is charged to "Operating Expenses - Fuel" in the consolidated statement of income (loss).
Stock-Based Compensation 
Stock-based compensation cost is measured at the grant date based on the fair value of the award. Ameren recognizes as compensation expense the estimated fair value of stock-based compensation on a straight-line basis over the requisite service period.
Excise Taxes 
Excise taxes levied on us are reflected on Ameren Missouri customer electric bills and on Ameren Missouri and Ameren Illinois customer natural gas bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the consolidated statement of income (loss). Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the customer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in “Taxes accrued” on the consolidated balance sheet.
Income Taxes 
Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.
We recognize that regulators will probably reduce future revenues for deferred tax liabilities that were initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded because of decreases in the statutory rate, have been credited to a regulatory liability. A regulatory asset has been established to recognize the probable recovery in rates of future income taxes, resulting principally from the reversal of allowance for funds used during construction. This refers to equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of the authoritative accounting guidance for income taxes.
Investment tax credits used on tax returns for prior years have been deferred for book purposes; the credits are being amortized over the useful lives of the related investment. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 - Income Taxes.
For certain renewable energy construction projects placed in service in 2010 and 2012, Ameren Missouri elected to seek federal cash tax grants in lieu of investment tax credits for which the projects also qualified.  These grants were accounted for using a grant recognition accounting model.  Ameren Missouri elected to reduce the basis of property as cash grants are received, which will reduce the amount of depreciation expense recognized in future periods.  In 2012, Ameren Missouri received $18 million in federal cash tax grants.
Ameren Missouri, Ameren Illinois, and all the other Ameren subsidiary companies are parties to a tax allocation agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax allocation agreement specifies that each party be allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution of capital to the party receiving the benefit.
Noncontrolling Interest 
Ameren’s noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren’s subsidiaries. These noncontrolling interests are classified as a component of equity separate from Ameren’s equity in its consolidated balance sheet.
Earnings Per Share 
There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2012, 2011, and 2010. The number of dilutive stock options, restricted stock shares, and performance share units had an immaterial impact on earnings per share. There were no assumed stock option conversions in 2010, as the remaining stock options were not dilutive. All of Ameren’s stock options expired in February 2010.
Accounting Changes and Other Matters 
The following is a summary of recently adopted authoritative accounting guidance as well as guidance issued but not yet adopted that could impact the Ameren Companies.
Disclosures about Fair Value Measurements
In May 2011, FASB issued additional authoritative guidance regarding fair value measurements. The guidance amended the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments did not affect Ameren's results of operations, financial position, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2012. See Note 8 - Fair Value Measurements for the required additional disclosures.
Presentation of Comprehensive Income
In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect Ameren's results of operations, financial position, or liquidity.
In February 2013, the FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. The amendments will not affect Ameren's results of operations, financial position, or liquidity, as this guidance only requires additional disclosures and substantially all the information that this amended guidance requires is already disclosed elsewhere in the financial statements. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2013 on a prospective basis.
Disclosures about Offsetting Assets and Liabilities
In December 2011, FASB issued additional authoritative guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The amendments will not affect Ameren's results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2013 with retrospective application required.
Asset Retirement Obligations 
Authoritative accounting guidance requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments to AROs based on changes in the estimated fair values of the obligations. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. Ameren has recorded AROs for retirement costs associated with Ameren Missouri for the Callaway energy center decommissioning costs, CCR storage facilities, and river structures. Also, Ameren has recorded AROs for retirement costs associated with Ameren Missouri and Ameren Illinois for asbestos removal and the disposal of certain transformers. After the New AER divestiture is complete, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers.
Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability.
Summary Of Significant Accounting Policies (Tables)
Schedule Of Materials And Supplies 
The following table presents a breakdown of materials and supplies at December 31, 2012, and 2011:
 
 
2012
 
Fuel(a)
$
198

Gas stored underground
131

Other materials and supplies
241

 
$
570

2011
 
Fuel(a)
$
150

Gas stored underground
171

Other materials and supplies
229

 
$
550

(a)
Consists of coal, oil, paint, propane, and tire chips.
Schedule Of Asset Retirement Obligations 
The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2012 and 2011:
 
Ameren(a)
 
Balance at December 31, 2010
$
403

 
Liabilities incurred
—

 
Liabilities settled
(2
)
 
Accretion in 2011(b)
22

 
Change in estimates(c)
(54
)
 
Balance at December 31, 2011
$
369

(d) 
Liabilities incurred
—

 
Liabilities settled
(6
)
 
Accretion in 2012(b)
20

 
Change in estimates(e)
(8
)
 
Balance at December 31, 2012
$
375

 
(a)
The nuclear decommissioning trust fund assets of 408 million and 357 million as of December 31, 2012, and 2011, respectively, were restricted for decommissioning of the Callaway energy center.
(b)
Accretion expense was recorded as an increase to regulatory assets.
(c)
Ameren changed its fair value estimate related to its Callaway energy center decommissioning costs because of a cost study performed in 2011 and a decline in the cost escalation factor assumptions. Additionally, Ameren changed the fair value estimates related to retirement costs for asbestos removal, river structures and CCR storage facilities.
(d)
Balance included $5 million in "Other current liabilities" on the consolidated balance sheet as of December 31, 2011.
(e)
Ameren changed the fair value estimates for asbestos removal. The estimates for asbestos removal costs at Hutsonville and Meredosia energy centers decreased because less asbestos than anticipated was found in the energy centers' structures during reviews made after the closure of these energy centers, and because removal was more cost efficient than anticipated due to the closure.
Rate And Regulatory Matters (Tables)
Schedule Of Regulatory Assets And Liabilities
The following table presents Ameren’s regulatory assets and regulatory liabilities at December 31, 2012, and 2011:
 
 
2012
2011
Current regulatory assets:
 
 
 
 
 
Under-recovered FAC(a)(b)
 
$
145

 
$
83

 
Under-recovered Illinois electric power costs(a)(c)
 
—

 
4

 
Under-recovered PGA(a)(c)
 
12

 
8

 
MTM derivative losses(d)
 
90


120

 
Total current regulatory assets
 
$
247

 
$
215

 
Noncurrent regulatory assets:
 
 
 
 
 
Pension and postretirement benefit costs(e)
 
$
772

 
$
878

 
Income taxes(f)
 
235

 
239

 
Asset retirement obligations(g)
 
5

 
6

 
Callaway costs(a)(h)
 
44

 
48

 
Unamortized loss on reacquired debt(a)(i)
 
181

 
47

 
Recoverable costs - contaminated facilities(j)
 
248

 
102

 
MTM derivative losses(d)
 
135


100


SO2 emission allowances sale tracker(k)
 
2

 
6

 
Storm costs(l)
 
9

 
16

 
Demand-side costs(a)(m)
 
73

 
70

 
Reserve for workers’ compensation liabilities(n)
 
12

 
13

 
Credit facilities fees(o)
 
6

 
10

 
Employee separation costs(p)
 
2

 
6

 
Common stock issuance costs(q)
 
7

 
10

 
Construction accounting for pollution control equipment(a)(r)
 
23

 
25

 
Other(s)
 
32

 
27

 
Total noncurrent regulatory assets
 
$
1,786

 
$
1,603

 
Current regulatory liabilities:
 
 
 
 
 
Over-recovered FAC(t)
 
$
—

 
$
12

 
Over-recovered Illinois electric power costs(c)
 
58

 
64

 
Over-recovered PGA(c)
 
15

 
9

 
MTM derivative gains(u)
 
19


46


Wholesale distribution refund(v)
 
8

 
2

 
Total current regulatory liabilities
 
$
100

 
$
133

 
Noncurrent regulatory liabilities:
 
 
 
 
 
Income taxes(w)
 
$
46

 
$
48

 
Removal costs(x)
 
1,347

 
1,269

 
Asset retirement obligation(g)
 
80

 
29

 
MTM derivative gains(u)
 
2


82


Bad debt rider(y)
 
12

 
10

 
Pension and postretirement benefit costs tracker(z)
 
23

 
38

 
Energy efficiency rider(aa)
 
20

 
24

 
IEIMA revenue requirement reconciliation(ab)
 
55

 
—

 
Other(ac)
 
4

 
2

 
Total noncurrent regulatory liabilities
 
$
1,589

 
$
1,502

 

(a)
These assets earn a return.
(b)
Under-recovered fuel costs for periods from June 2010 through December 2012. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months.
(c)
Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral.
(d)
Deferral of commodity-related derivative MTM losses. The December 31, 2011 balance included the MTM losses on financial contracts entered into by Ameren Illinois with Marketing Company, which expired in December 2012.
(e)
These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 - Retirement Benefits for additional information.
(f)
Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 - Income Taxes for amortization period.
(g)
Recoverable or refundable removal costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations.
(h)
Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the energy center's current operating license which expires in 2024.
(i)
Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.
(j)
The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of actual expenditures. See Note 15 - Commitments and Contingencies for additional information.
(k)
A regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order. The MoPSC’s May 2010 electric rate order discontinued any future deferrals under this tracking mechanism. The MoPSC’s December 2012 rate order approved the amortization of these costs through December 2014.
(l)
Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. As approved by the December 2012 MoPSC electric rate order, the 2006, 2007, and 2008 storm costs are being amortized through December 2014. As approved by the May 2010 MoPSC electric rate order, the 2009 storm costs are being amortized through June 2015.
(m)
Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. Costs incurred from May 2008 through September 2008 are being amortized over a 10-year period that began in March 2009. Costs incurred from October 2008 through December 2009 are being amortized over a six-year period that began in July 2010. Costs incurred from January 2010 through February 2011 are being amortized over a six-year period that began in August 2011. Costs incurred from March 2011 through July 2012 are being amortized over a six-year period that began in January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case.
(n)
Reserve for workers’ compensation claims. The period of recovery will depend on the timing of actual expenditures.
(o)
Ameren Missouri’s costs incurred to enter into and maintain the 2012 Ameren Missouri Credit Agreement. These costs are being amortized over five years, beginning in November 2012. These costs are being amortized to construction work in progress, which will be subsequently depreciated when assets are placed into service.
(p)
Costs incurred for voluntary and involuntary separation programs. The 2009 Ameren Missouri-related costs are being amortized over two years, beginning in January 2013, as approved by the December 2012 MoPSC electric rate order. The 2009 Ameren Illinois-related costs are being amortized over three years, beginning in May 2010, as approved by the April 2010 ICC electric and natural gas rate order.
(q)
The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to recover its portion of Ameren’s September 2009 common stock issuance costs. These costs are being amortized over five years, beginning in July 2010.
(r)
The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was placed in customer rates. The amortization of these costs will be over the expected life of the Sioux energy center.
(s)
The Ameren Illinois total includes Ameren Illinois Merger integration and optimization costs, which are amortized over four years, beginning in January 2012. The Ameren Illinois total includes costs related to delivery service rate cases. The 2012 natural gas rate case costs are being amortized over a two-year period that began in January 2012. The electric rate case costs for the IEIMA initial rate filing are being amortized over a three-year period that began in January 2012. The Ameren Illinois total also includes a portion of the unamortized debt fair value adjustment recorded upon Ameren's acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007. At Ameren Missouri, the balance primarily includes cost associated with the retirement of renewable energy credits and solar rebates to fulfill its renewable energy portfolio requirement. Costs incurred from January 2010 through July 2012 are being amortized over three years, beginning January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case.
(t)
Over-recovered fuel costs from March 2009 through September 2009 as ordered by the MoPSC in April 2011. Customer refunds concluded in 2012. Specific accumulation periods aggregate the over-recovered costs over four months, any related adjustments occur over the following four months, and then recovery from customers occurs over the next eight months.
(u)
Deferral of commodity-related derivative MTM gains.
(v)
Estimated refund to wholesale electric customers. See 2011 Wholesale Distribution Rate Case above.
(w)
Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 - Income Taxes for amortization period.
(x)
Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations.
(y)
A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by Ameren Illinois under GAAP and the level of such costs included in electric and natural gas rates. The over-recovery relating to 2010 was refunded to customers from June 2011 through May 2012. The over-recovery relating to 2011 is being refunded to customers from June 2012 through May 2013. The over-recovery relating to 2012 will be refunded to customers from June 2013 through May 2014.
(z)
A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs built into rates. For periods prior to August 2012, the MoPSC's December 2012 electric rate order directed the amortization to occur over five years, beginning in January 2013. For periods after August 2012, the amortization period will be determined in a future Ameren Missouri electric rate case.
(aa)
A regulatory tracking mechanism that allows Ameren Illinois to recover its electric and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. This over-recovery will be refunded to customers over the following 12 months after the plan year.
(ab)
The difference between Ameren Illinois' 2012 revenue requirement calculated under the IEIMA's performance-based formula ratemaking framework, and the revenue requirement included in customer rates for 2012. Subject to ICC approval, this liability will be refunded to customers in 2014.
(ac)
Balance primarily includes an Ameren Missouri liability relating to its 2010 property tax refund. The MoPSC's December 2012 electric rate order directed a refund to customers over a two-year period, beginning in January 2013.
Property And Plant, Net (Tables)
Schedule Of Property And Plant, Net 
The following table presents Ameren's property and plant, net, at December 31, 2012, and 2011:
 
Ameren(a)
2012
 
Property and plant, at original cost:
 
Electric
$
20,942

Natural gas
1,854

 
22,796

Less: Accumulated depreciation and amortization
8,346

 
14,450

Construction work in progress:
 
Nuclear fuel in process
317

Other
581

Property and plant, net
$
15,348

2011
 
Property and plant, at original cost:
 
Electric
$
20,098

Natural gas
1,751

 
21,849

Less: Accumulated depreciation and amortization
7,868

 
13,981

Construction work in progress:
 
Nuclear fuel in process
255

Other
612

Property and plant, net
$
14,848


(a)
Amounts include two electric generation CTs under two separate capital lease agreements. The gross asset value of those agreements was $228 million and $229 million at December 31, 2012, and 2011, respectively. The total accumulated depreciation associated with the two CTs was $52 million and $52 million at December 31, 2012, and 2011, respectively. In addition, Ameren has investments in debt securities, which are classified as held-to-maturity, related to the two CTs from the city of Bowling Green and Audrain County. As of December 31, 2012, and 2011, the carrying value of these debt securities was $304 million and $309 million, respectively.
Accrued Capital Expenditures 
The following table provides accrued capital expenditures at December 31, 2012, 2011, and 2010, which represent noncash investing activity excluded from the statements of cash flows:
2012
$
103

2011
92

2010
70

Short-Term Debt And Liquidity (Tables)
Schedule Of Maximum Aggregate Amount Available On Credit Agreements 
The maximum aggregate amount available to each borrower under each facility is shown in the following table (such amount being such borrower's "Borrowing Sublimit"):
 
2012 Missouri Credit Agreement
2012 Illinois
Credit Agreement
Ameren
$
500

$
300

Ameren Missouri
800

(a)

Ameren Illinois
(a)

$
800

Borrowing Activity On Credit Agreements 
The following table summarizes the borrowing activity and relevant interest rates under the 2010 Missouri Credit Agreement, which terminated on November 14, 2012, for the years ended December 31, 2012, and 2011 and excludes issued letters of credit. Ameren, Ameren Missouri and Ameren Illinois did not borrow under the 2012 Credit Agreements from November 14, 2012, through December 31, 2012.
2010 Missouri Credit Agreement ($800 million) (Terminated)
Ameren
(Parent)
 
Ameren
Missouri
 
Total
2012
 
 
 
 
 
Average daily borrowings outstanding during 2012(a)
$
—

 
$
1

 
$
1

Outstanding credit facility borrowings at period end
—

 
—

 
—

Weighted-average interest rate during 2012(a)
—
%
 
4.15
%
 
4.15
%
Peak credit facility borrowings during 2012(a)
$
—

 
$
50

 
$
50

Peak interest rate during 2012
—
%
 
4.15
%
 
4.15
%
2011
 
 
 
 
 
Average daily borrowings outstanding during 2011
$
105

 
$
—

 
$
105

Outstanding credit facility borrowings at period end
—

 
—

 
—

Weighted-average interest rate during 2011
2.30
%
 
—

 
2.30
%
Peak credit facility borrowings during 2011
$
340

 
$
—

 
$
340

Peak interest rate during 2011
4.30
%
 
—

 
4.30
%
(a)
Calculated through termination date.
Long-Term Debt And Equity Financings (Tables)
Schedule of Long-term Debt Instruments 
The following table presents Ameren's long-term debt outstanding, including maturities due within one year, as of December 31, 2012, and 2011:
 
2012
 
2011
Ameren (Parent):
 
 
 
8.875% Senior unsecured notes due 2014
$
425

 
$
425

Less: Unamortized discount and premium
(1
)
 
(1
)
Long-term debt, net
$
424

 
$
424

Ameren Missouri:
 
 
 
Senior secured notes:(a)
 
 
 
5.25% Senior secured notes due 2012
$
—

 
$
173

4.65% Senior secured notes due 2013
200

 
200

5.50% Senior secured notes due 2014
104

 
104

4.75% Senior secured notes due 2015
114

 
114

5.40% Senior secured notes due 2016
260

 
260

6.40% Senior secured notes due 2017
425

 
425

6.00% Senior secured notes due 2018(b)
179

 
250

5.10% Senior secured notes due 2018
199

 
200

6.70% Senior secured notes due 2019(b)
329

 
450

5.10% Senior secured notes due 2019
244

 
300

5.00% Senior secured notes due 2020
85

 
85

5.50% Senior secured notes due 2034
184

 
184

5.30% Senior secured notes due 2037
300

 
300

8.45% Senior secured notes due 2039(b)
350

 
350

3.90% Senior secured notes due 2042(b)
485

 
—

Environmental improvement and pollution control revenue bonds:
 
 
 
1992 Series due 2022(c)(d)
47

 
47

1993 5.45% Series due 2028(e)
44

 
44

1998 Series A due 2033(c)(d)
60

 
60

1998 Series B due 2033(c)(d)
50

 
50

1998 Series C due 2033(c)(d)
50

 
50

Capital lease obligations:
 
 
 
City of Bowling Green capital lease (Peno Creek CT) through 2022
64

 
69

Audrain County capital lease (Audrain County CT) due 2023
240

 
240

Total long-term debt, gross
4,013

 
3,955

Less: Unamortized discount and premium
(7
)
 
(5
)
Less: Maturities due within one year
(205
)
 
(178
)
Long-term debt, net
$
3,801

 
$
3,772

 
2012
 
2011
Ameren Illinois:
 
 
 
Senior secured notes:
 
 
 
8.875% Senior secured notes due 2013(f)(h)
$
150

 
$
150

6.20% Senior secured notes due 2016(f)
54

 
54

6.25% Senior secured notes due 2016(g)
75

 
75

6.125% Senior secured notes due 2017(g)(i)
250

 
250

6.25% Senior secured notes due 2018(g)(i)
144

 
337

9.75% Senior secured notes due 2018(g)(i)
313

 
400

2.70% Senior secured notes due 2022(g)(i)
400

 
—

6.125% Senior secured notes due 2028(g)
60

 
60

6.70% Senior secured notes due 2036(g)
61

 
61

6.70% Senior secured notes due 2036(f)
42

 
42

Environmental improvement and pollution control revenue bonds:
 
 
 
6.20% Series 1992B due 2012
—

 
1

2000 Series A 5.50% due 2014
—

 
51

5.90% Series 1993 due 2023(j)
32

 
32

5.70% 1994A Series due 2024(k)
36

 
36

1993 Series C-1 5.95% due 2026(l)
35

 
35

1993 Series C-2 5.70% due 2026(l)
8

 
8

1993 Series B-1 due 2028(d)(l)
17

 
17

5.40% 1998A Series due 2028(k)
19

 
19

5.40% 1998B Series due 2028(k)
33

 
33

Fair-market value adjustments
4

 
5

Total long-term debt, gross
1,733

 
1,666

Less: Unamortized discount and premium
(6
)
 
(8
)
Less: Maturities due within one year
(150
)
 
(1
)
Long-term debt, net
$
1,577

 
$
1,657

Ameren consolidated long-term debt, net
$
5,802

 
$
5,853

(a)
These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042.
(b)
Ameren Missouri has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its first mortgage bonds. Ameren Missouri has also agreed to prevent a first mortgage bond release date from occurring as long as any of the 8.45% senior secured notes due 2039 and any of the 3.90% senior secured notes due 2042 remain outstanding.
(c)
These bonds are secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri's senior secured notes. The bonds are also backed by an insurance guarantee policy.
(d)
Interest rates, and periods during which such rates apply, vary depending on our selection of defined rate modes. Maximum interest rates could range up to 18% depending on the series of bonds. The average interest rates for 2012 and 2011 were as follows:
 
2012
 
2011
Ameren Missouri 1992 Series
0.30
%
 
0.34
%
Ameren Missouri 1998 Series A
0.65
%
 
0.69
%
Ameren Missouri 1998 Series B
0.64
%
 
0.68
%
Ameren Missouri 1998 Series C
0.64
%
 
0.69
%
Ameren Illinois 1993 Series B-1
0.22
%
 
0.28
%

(e)
These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and are secured by substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value.
(f)
These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the CILCO first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2023.
(g)
These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028.
(h)
Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its CILCO first mortgage bonds, and therefore a CILCO first mortgage bond release date will not occur while any of such notes are outstanding.
(i)
Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its Ameren Illinois mortgage bonds, and therefore an Ameren Illinois first mortgage bond release date will not occur as long as any of these notes are outstanding.
(j)
These bonds are first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture and are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value.
(k)
These bonds are mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture and are secured by substantially all property of the former IP and CIPS. The bonds are callable at 100% of par value. The bonds are also backed by an insurance guarantee policy.
(l)
The bonds are callable at 100% of par value.
Schedule Of Maturities Of Long-Term Debt 
The following table presents Ameren's aggregate maturities of long-term debt, including current maturities, at December 31, 2012:
 
 Ameren
(Parent)(a)
 
 Ameren
Missouri(a)
 
 Ameren
Illinois(a)(b)
 
Ameren
Consolidated
2013
$
—

 
$
205

 
$
150

 
$
355

2014
425

 
109

 
—

 
534

2015
—

 
120

 
—

 
120

2016
—

 
266

 
129

 
395

2017
—

 
431

 
250

 
681

Thereafter
—

 
2,882

 
1,200

 
4,082

Total
$
425

 
$
4,013

 
$
1,729

 
$
6,167

(a)
Excludes unamortized discount and premium of $1 million, $7 million, and $6 million at Ameren (Parent), Ameren Missouri, and Ameren Illinois, respectively.
(b)
Excludes $4 million related to Ameren Illinois’ long-term debt fair-market value adjustments, which are being amortized to interest expense over the remaining life of the debt.
Schedule Of Outstanding Preferred Stock 
 
 
 
Redemption Price(per share)
 
2012
 
2011
Ameren Missouri:
 
 
 
 
 
 
 
Without par value and stated value of $100 per share, 25 million shares authorized
 
 
 
 
 
 
$3.50 Series
130,000 shares
 
$
110.00

 
$
13

 
$
13

$3.70 Series
40,000 shares
 
104.75

 
4

 
4

$4.00 Series
150,000 shares
 
105.625

 
15

 
15

$4.30 Series
40,000 shares
 
105.00

 
4

 
4

$4.50 Series
213,595 shares
 
110.00

(a) 
21

 
21

$4.56 Series
200,000 shares
 
102.47

 
20

 
20

$4.75 Series
20,000 shares
 
102.176

 
2

 
2

$5.50 Series A
14,000 shares
 
110.00

 
1

 
1

Total
 
 
 
$
80

 
$
80

Ameren Illinois:
 
 
 
 
 
 
 
With par value of $100 per share, 2 million shares authorized
 
 
 
 
 
 
4.00% Series
144,275 shares
 
$
101.00

 
$
14

 
$
14

4.08% Series
45,224 shares
 
103.00

 
5

 
5

4.20% Series
23,655 shares
 
104.00

 
2

 
2

4.25% Series
50,000 shares
 
102.00

 
5

 
5

4.26% Series
16,621 shares
 
103.00

 
2

 
2

4.42% Series
16,190 shares
 
103.00

 
2

 
2

4.70% Series
18,429 shares
 
103.00

 
2

 
2

4.90% Series
73,825 shares
 
102.00

 
7

 
7

4.92% Series
49,289 shares
 
103.50

 
5

 
5

5.16% Series
50,000 shares
 
102.00

 
5

 
5

6.625% Series
124,273.75 shares
 
100.00

 
12

 
12

7.75% Series
4,542 shares
 
100.00

 
1

 
1

Total
 
 
 
$
62

 
$
62

Total Ameren(b)
 
 
 
$
142

 
$
142

(a)
In the event of voluntary liquidation, $105.50.
Schedule of Required and Actual Debt Ratios 
The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable as of December 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.
 
Required Interest
Coverage Ratio(a)
Actual Interest
Coverage Ratio
Bonds Issuable(b)
 
Required Dividend
Coverage Ratio(c)
Actual Dividend
Coverage Ratio
Preferred Stock
Issuable
Ameren Missouri
          >2.0
4.6

$
4,056

  
>2.5
122.8

$
2,351

Ameren Illinois
          >2.0
7.1

3,439

(d) 
>1.5
2.8

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.
Aggregate Principal Amount Of Maturities 
The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:
Senior Secured Notes
Principal Amount Repurchased
 
Premium Plus Accrued
and Unpaid Interest(a)
 
Principal Amount Outstanding After Tender Offer
6.00% senior secured notes due 2018
$
71

 
$
19

 
$
179

6.70% senior secured notes due 2019
121

 
35

 
329

5.10% senior secured notes due 2018
1

 
(b)

 
199

5.10% senior secured notes due 2019
56

 
12

 
244

(a)
The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $485 million 3.90% senior secured notes due 2042.
(b)
Amount is less than $1 million.
Aggregate Principal Amount Of Maturities 
The following table sets forth the aggregate principal amount of each series of notes repurchased, along with certain other items of the tender offer:
Senior Secured Notes
Principal Amount Repurchased
 
Premium Plus Accrued
and Unpaid Interest(a)
 
Principal Amount Outstanding After Tender Offer
9.75% senior secured notes due 2018
$
87

 
$
36

 
$
313

6.25% senior secured notes due 2018
194

 
47

 
144

(a)
The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $400 million 2.70% senior secured notes due 2022.
Other Income And Expenses (Tables)
Other Income And Expenses
The following table presents the components of "Other Income and Expenses" in Ameren's consolidated statement of income (loss) for the years ended December 31, 2012, 2011, and 2010:
 
2012
 
2011
 
2010
Ameren:
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
Interest and dividend income
$
4

(a) 
$
3

 
$
4

Interest income on industrial development revenue bonds
28

 
28

 
28

Allowance for equity funds used during construction
36

 
34

 
52

Other
2

 
3

 
4

Total miscellaneous income
$
70

 
$
68

 
$
88

Miscellaneous expense:
 
 
 
 
 
Donations
$
24

(b) 
$
8

 
$
19

Other
13

 
15

 
13

Total miscellaneous expense
$
37

 
$
23

 
$
32

(a)
Includes interest income relating to a 2012 refund of charges included in an expired power purchase agreement with Entergy. See Note 2 - Rate and Regulatory Matters for additional information.
(b)
Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' 2012 participation in the formula ratemaking process.
Derivative Financial Instruments (Tables)
Open Gross Derivative Volumes By Commodity Type 
The following table presents open gross commodity contract volumes by commodity type as of December 31, 2012, and 2011:
  
Quantity (in millions, except as indicated)
Commodity
Accrual & NPNS
Contracts(a)
 
Other
Derivatives(b)
 
Derivatives That Qualify for
Regulatory Deferral(c)
 
2012
 
2011
 
2012
 
2011
 
2012
 
2011
Coal (in tons)
96

 
116

 
(d)

 
(d)

 
(d)

 
(d)

Fuel oils (in gallons)(e)
(d)

 
(d)

 
(d)

 
(d)

 
70

 
53

Natural gas (in mmbtu)
20

 
50

 
—

 
9

 
147

 
193

Power (in megawatthours)
24

 
12

 
2

 
1

 
23

 
21

Renewable energy credits(f)
15

 
16

 
(d)

 
(d)

 
(d)

 
(d)

Uranium (pounds in thousands)
5,142

 
5,553

 
(d)

 
(d)

 
446

 
148

(a)
Accrual contracts include commodity contracts that do not qualify as derivatives. As of December 31, 2012, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.
(b)
As of December 31, 2012, these contracts ran through December 2014 for power.
(c)
As of December 31, 2012, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively.
(d)
Not applicable.
(e)
Fuel oils consist of heating and crude oil.
(f)
A renewable energy credit is created for every megawatthour of renewable energy generated. Ameren contracts include renewable energy credits from solar and wind-generated power.
Derivative Instruments Carrying Value 
The following table presents the carrying value and balance sheet location of all derivative instruments as of December 31, 2012, and 2011:
 
Balance Sheet Location
 
2012
 
2011
Derivative assets not designated as hedging instruments(a)
 
 
 
 
Commodity contracts:
 
 
 
 
Fuel oils
Other current assets
 
$
8

 
$
17

 
Other assets
 
4

 
6

Natural gas
Other current assets
 
1

 
3

 
Other assets
 
1

 
1

Power
Other current assets
 
14

 
30

 
Other assets
 
1

 
77

 
Total assets
 
$
29

 
$
134

Derivative liabilities not designated as hedging instruments(a)
 
 
 
 
Commodity contracts:
 
 
 
 
 
Fuel oils
MTM derivative liabilities
 
$
2

 
$
1

 
Other deferred credits and liabilities
 
2

 
—

Natural gas
MTM derivative liabilities
 
64

 
103

 
Other deferred credits and liabilities
 
45

 
92

Power
MTM derivative liabilities
 
25

 
18

 
Other deferred credits and liabilities
 
90

 
8

Uranium
MTM derivative liabilities
 
1

 
—

 
Other deferred credits and liabilities
 
1

 
1

 
Total liabilities
 
$
230

 
$
223

(a)
Includes derivatives subject to regulatory deferral.
Cumulative Pretax Net Gains (Losses) On All Derivative Instruments In OCI 
The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred in regulatory assets or regulatory liabilities as of December 31, 2012, and 2011:
 
 
2012
 
2011
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
Fuel oils derivative contracts(a)
 
$
4

 
$
19

Natural gas derivative contracts(b)
 
(107
)
 
(191
)
Power derivative contracts(c)
 
(99
)
 
81

Uranium derivative contracts(d)
 
(2
)
 
(1
)


(a)
Represents net gains on fuel oils derivative contracts. These contracts are a partial hedge of transportation costs for coal through October 2015 as of December 31, 2012. Current gains deferred as regulatory liabilities include $4 million as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012.
(b)
Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2017 as of December 31, 2012. Current gains deferred as regulatory liabilities include $1 million as of December 31, 2012. Current losses deferred as regulatory assets include $64 million as of December 31, 2012.
(c)
Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 as of December 31, 2012. Current gains deferred as regulatory liabilities include $14 million as of December 31, 2012. Current losses deferred as regulatory assets include $24 million as of December 31, 2012.
(d)
Represents net losses on uranium derivative contracts. These contracts are a partial hedge of uranium requirements through September 2014 as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012, respectively.
Maximum Exposure If Counterparties Fail To Perform On Contracts 
The following table presents by groupings the maximum exposure, as of December 31, 2012, and 2011, if counterparty groups were to fail completely to perform on contracts. The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.
 
Affiliates
 
Coal
Producers
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Total
2012
$
—

 
$
—

 
$
2

 
$
3

 
$
15

 
$
3

 
$
23

2011
$
1

 
$
35

 
$
85

 
$
4

 
$
27

 
$
4

 
$
156

Potential Loss On Counterparty Exposures 
The following table presents the potential loss after consideration of the application of master trading and netting agreements and collateral held as of December 31, 2012, and 2011:
 
Affiliates
 
Coal
Producers
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Total
2012
$
—

 
$
—

 
$
1

 
$
1

 
$
10

 
$
3

 
$
15

2011
$
1

 
$
35

 
$
85

 
$
3

 
$
22

 
$
4

 
$
150

Derivative Instruments With Credit Risk-Related Contingent Features 
The following table presents, as of December 31, 2012, and 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements assuming (1) the credit risk-related contingent features underlying these agreements were triggered on December 31, 2012, or 2011, respectively, and (2) those counterparties with rights to do so requested collateral:
 
Aggregate Fair Value of
Derivative Liabilities(a)
 
Cash
Collateral Posted
 
Potential Aggregate Amount of
Additional Collateral Required(b)
2012
$
226

 
$
61

 
$
155

2011
$
322

 
$
104

 
$
211

(a)
Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures.
(b)
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.
Other Derivatives 
The following table represents the net change in market value associated with derivatives not designated as hedging instruments for the years ended December 31, 2012, and 2011:
 
 
Location of Gain (Loss)
Recognized in Income
 
Gain (Loss) Recognized
in Income
 
2012
 
2011
Natural gas (generation)
 
Operating Expenses - Fuel
 
$
—

 
$
(1
)

Derivatives That Qualify For Regulatory Deferral 
The following table represents the net change in market value associated with derivatives that qualify for regulatory deferral for the years ended December 31, 2012, and 2011:
  
 
Gain (Loss) Recognized
In Regulatory Liabilities
or Regulatory Assets
2012
 
2011
Fuel oils
 
$
(15
)
 
$
—

Natural gas
 
84

 
(26
)
Power
 
(180
)
 
80

Uranium
 
(1
)
 
(3
)
Total
 
$
(112
)
 
$
51

Fair Value Measurements (Tables)
Fair Value Inputs, Assets and Liabilities, Quantitative Information 
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:
 
Fair Value
 
 
Range [Weighted
 
Assets
Liabilities
Valuation Technique(s)
Unobservable Input
 Average]
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
Fuel oils
$
8

$
(3
)
Discounted cash flow
Escalation rate(%)(b)
.21 - .60 [.44]
 
 
 
 
Counterparty credit risk(%)(c)(d)
.12 - 1 [1]
 
 
 
 
Ameren credit risk(%)(c)(d)
2
 
 
 
Option model
Volatilities(%)(b)
7 - 27 [24]
Power(e)
14

(114
)
Discounted cash flow
Average bid/ask consensus peak and off-peak pricing - forwards/swaps($/MWh)(c)
22 - 47 [31]
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(281) - 1,851 [178]
 
 
 
 
Nodal basis($/MWh)(c)
(5) - (1) [(3)]
 
 
 
 
Counterparty credit risk(%)(c)(d)
.22 - 1 [1]
 
 
 
 
Ameren credit risk(%)(c)(d)
2 - 5 [5]
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 8 [6]
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7 [6]
Uranium
—

(2
)
Discounted cash flow
Average bid/ask consensus pricing($/pound)(b)
43 - 46 [44]
(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 credit risk is only applied to counterparties with derivative liability balances.
(e)
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.
Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis 
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
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
 
$
269

 
$
144

 
$
22

 
$
435

Liabilities:
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
1

 
—

 
3

 
4

 
Natural gas
 
7

 
102

 
—

 
109

 
Power
 
—

 
1

 
114

 
115

 
Uranium
 
—

 
—

 
2

 
2

 
Total
 
$
8

 
$
103

 
$
119

 
$
230

(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.
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2011:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
20

 
$
—

 
$
3

 
$
23

 
Natural gas
 
2

 
—

 
2

 
4

 
Power
 
—

 
1

 
106

 
107

 
Total derivative assets - commodity contracts
 
$
22

 
$
1

 
$
111

 
$
134

 
Nuclear decommissioning trust fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
3

 
—

 
—

 
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
234

 
—

 
—

 
234

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
44

 
—

 
44

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
65

 
—

 
65

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
237

 
$
121

 
$
—

 
$
358

 
Total
 
$
259

 
$
122

 
$
111

 
$
492

Liabilities:
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
1

 
$
—

 
$
—

 
$
1

 
Natural gas
 
19

 
—

 
176

 
195

 
Power
 
—

 
1

 
25

 
26

 
Uranium
 
—

 
—

 
1

 
1

 
Total
 
$
20

 
$
1

 
$
202

 
$
223

(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.
Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level 3 In The Fair Value Hierarchy 
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012, and 2011:
  
 
Net Derivative Commodity Contracts
  
 
2012
 
2011
Fuel oils:
 
 
 
 
Beginning balance at January 1
 
$
3

 
$
30

Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(1
)
 
19

Total realized and unrealized gains (losses)
 
(1
)
 
19

Purchases
 
7

 
4

Sales
 
(3
)
 
(1
)
Settlements
 
(2
)
 
(30
)
Transfers into Level 3
 
1

 
—

Transfers out of Level 3
 
—

 
(19
)
Ending balance at December 31
 
$
5

 
$
3

Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
(1
)
 
$
(11
)
Natural gas:
 
 
 
 
Beginning balance at January 1
 
$
(174
)
 
$
(148
)
Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(27
)
 
(115
)
Total realized and unrealized gains (losses)
 
(27
)
 
(115
)
Purchases
 
—

 
1

Sales
 
—

 
(1
)
Settlements
 
16

 
89

Transfers out of Level 3
 
185

 
—

Ending balance at December 31
 
$
—

 
$
(174
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
—

 
$
(78
)
Power:
 
 
 
 
Beginning balance at January 1
 
$
81

 
$
19

Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(175
)
 
55

Total realized and unrealized gains (losses)
 
(175
)
 
55

Purchases
 
21

 
30

Sales
 
(1
)
 
(1
)
Settlements
 
(22
)
 
(22
)
Transfers into Level 3
 
—

 
(1
)
Transfers out of Level 3
 
(4
)
 
1

Ending balance at December 31
 
$
(100
)
 
$
81

Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
(175
)
(a) 
$
(25
)
Uranium:
 
 
 
 
Beginning balance at January 1
 
$
(1
)
 
$
2

Realized and unrealized gains (losses):
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(3
)
Total realized and unrealized gains (losses)
 
(2
)
 
(3
)
Purchases
 
—

 
(1
)
Settlements
 
1

 
1

Ending balance at December 31
 
$
(2
)
 
$
(1
)
Change in unrealized gains (losses) related to assets/liabilities held at December 31
 
$
(1
)
 
$
—

(a)
The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois swap contracts, which expire in May 2032.

Schedule Of Transfers Between Fair Value Hierarchy Levels 
The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the years ended December 31, 2012, and 2011:
 
2012
 
2011
Derivative commodity contracts:



Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
1

 
$
—

Transfers out of Level 3 / Transfers into Level 1 - Fuel oils
—

 
(19
)
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
185

 
—

Transfers into Level 3 / Transfers out of Level 2 - Power
—

 
(1
)
Transfers out of Level 3 / Transfers into Level 2 - Power
(4
)
 
1

Net fair value of Level 3 transfers
$
182

 
$
(19
)
Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock 
The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 2012, and 2011:
  
2012
 
2011
  
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt and capital lease obligations (including current portion)
$
6,157

 
$
7,110

 
$
6,032

 
$
6,961

Preferred stock(a)
142

 
123

 
142

 
92

(a)
Preferred stock along with the noncontrolling interest of EEI is recorded in "Noncontrolling Interests" on the consolidated balance sheet.
Nuclear Decommissioning Trust Fund Investments (Tables)
Fair Value Of Securities In Nuclear Decommissioning Trust Fund 
The following table presents the costs and fair values of investments in debt and equity securities in Ameren Missouri’s nuclear decommissioning trust fund at December 31, 2012, and 2011:
Security Type
Cost
 
Gross Unrealized Gain
 
Gross Unrealized Loss
 
Fair Value
2012
 
 
 
 
 
 
 
Debt securities
$
133

 
$
8

 
(a)

 
$
141

Equity securities
145

 
130

 
11

 
264

Cash
1

 
—

 
—

 
1

Other(b)
2

 
—

 
—

 
2

Total
$
281

 
$
138

 
$
11

 
$
408

2011
 
 
 
 
 
 
 
Debt securities
$
114

 
$
7

 
(a)

 
$
121

Equity securities
145

 
101

 
12

 
234

Cash
3

 
—

 
—

 
3

Other(b)
(1
)
 
—

 
—

 
(1
)
Total
$
261

 
$
108

 
$
12

 
$
357

(a)
Amount less than $1 million.
(b)
Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest receivables.
Schedule Of Unrealized Losses On Available-For-Sale Investments Included In Nuclear Decommissioning Trust Fund 
They are aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position at December 31, 2012:
  
Less than 12 Months
 
12 Months or Greater
 
Total
  
Fair Value
 
Gross
Unrealized
Losses
 
Fair Value
 
Gross
Unrealized
Losses
 
Fair Value
 
Gross
Unrealized
Losses
Debt securities
$
17

 
$ (a)

 
$ (a)

 
$ (a)

 
$
17

 
$ (a)

Equity securities
7

 
1

 
14

 
10

 
21

 
11

Total
$
24

 
$
1

 
$
14

 
$
10

 
$
38

 
$
11

(a)
Amount less than $1 million.
Proceeds From Sale Of Investments In Nuclear Decommissioning Trust Fund And Gross Realized Gains And Losses 
The following table presents proceeds from the sale and maturities of investments in Ameren Missouri’s nuclear decommissioning trust fund and the gross realized gains and losses resulting from those sales for the years ended December 31, 2012, 2011, and 2010:
 
2012
 
2011
 
2010
Proceeds from sales and maturities
$
384

 
$
199

 
$
256

Gross realized gains
6

 
5

 
5

Gross realized losses
2

 
4

 
4

Fair Value Of Securities In Nuclear Decommissioning Trust Fund According To Their Contractual Maturities 
The following table presents the costs and fair values of investments in debt securities in Ameren Missouri’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2012:
 
Cost
 
Fair Value
Less than 5 years
$
78

 
$
79

5 years to 10 years
32

 
35

Due after 10 years
23

 
27

Total
$
133

 
$
141

Retirement Benefits (Tables)
Funded Status Of Benefit Plans And Amounts Included In Regulatory Assets And OCI 
The following table presents the funded status of our pension and postretirement benefit plans as of December 31, 2012, and 2011. It also provides the amounts included in regulatory assets and accumulated OCI at December 31, 2012, and 2011, that have not been recognized in net periodic benefit costs.
  
2012
 
2011
  
Pension Benefits
 
Postretirement
Benefits
 
Pension Benefits
 
Postretirement
Benefits
Accumulated benefit obligation at end of year
$
3,829

 
(a)

 
$
3,553

 
(a)

Change in benefit obligation:
 
 
 
 
 
 
 
Net benefit obligation at beginning of year
$
3,764

 
$
1,145

 
$
3,366

 
$
1,036

Service cost
81

 
22

 
73

 
20

Interest cost
166

 
47

 
175

 
54

Plan amendments(b)
—

 
—

 
(16
)
 
—

Participant contributions
—

 
16

 
—

 
18

Actuarial (gain) loss
240

 
(10
)
 
335

 
71

Benefits paid
(200
)
 
(69
)
 
(169
)
 
(63
)
Early retiree reinsurance program receipt
(a)

 
2

 
(a)

 
3

Federal subsidy on benefits paid
(a)

 
4

 
(a)

 
6

Net benefit obligation at end of year
4,051

 
1,157

 
3,764

 
1,145

Change in plan assets:
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
2,814

 
836

 
2,664

 
735

Actual return on plan assets
385

 
104

 
223

 
8

Employer contributions
128

 
45

 
96

 
129

Federal subsidy on benefits paid
(a)

 
4

 
(a)

 
6

Early retiree reinsurance program receipt
(a)

 
2

 
(a)

 
3

Participant contributions
—

 
16

 
—

 
18

Benefits paid
(200
)
 
(69
)
 
(169
)
 
(63
)
Fair value of plan assets at end of year
3,127

 
938

 
2,814

 
836

Funded status - deficiency
924

 
219

 
950

 
309

Accrued benefit cost at December 31
$
924

 
$
219

 
$
950

 
$
309

Amounts recognized in the consolidated balance sheet consist of:
 
 
 
 
 
 
 
Current liability
$
3

 
$
2

 
$
3

 
$
3

Noncurrent liability
921

 
217

 
947

 
306

Net liability recognized
$
924

 
$
219

 
$
950

 
$
309

Amounts recognized in regulatory assets consist of:
 
 
 
 
 
 
 
Net actuarial loss
$
699

 
$
103

 
$
734

 
$
177

Prior service cost (credit)
(6
)
 
(24
)
 
(7
)
 
(28
)
Transition obligation
—

 
—

 
—

 
2

Amounts (pretax) recognized in accumulated OCI consist of:
 
 
 
 
 
 
 
Net actuarial loss
65

 
5

 
54

 
5

Prior service cost (credit)
(14
)
 
(6
)
 
(16
)
 
(7
)
Total
$
744

 
$
78

 
$
765

 
$
149

(a)
Not applicable.
(b)
In 2011, Ameren’s pension plan was amended to adjust the calculation of the future benefit obligation of approximately 430 labor union-represented employees from a traditional, final pay formula to a cash balance formula.
Assumptions Used To Determine Benefit Obligations 
The following table presents the assumptions used to determine our benefit obligations at December 31, 2012, and 2011:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2012
 
2011
Discount rate at measurement date
4.00
%
 
4.50
%
 
4.00
%
 
4.50
%
Increase in future compensation
3.50

 
3.50

 
3.50

 
3.50

Medical cost trend rate (initial)
—

 
—

 
5.00

 
5.50

Medical cost trend rate (ultimate)
—

 
—

 
5.00

 
5.00

Years to ultimate rate
0

 
0

 
0

 
1 year

Schedule Of Cash Contributions Made To Benefit Plans 
The following table presents the cash contributions made to our defined benefit retirement plan and to our postretirement plans during 2012, 2011, and 2010:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2010
 
2012
 
2011
 
2010
 
$
128

 
$
96

 
$
81

 
$
45

 
$
129

 
$
36

Target Allocation Of The Plans' Asset Categories 
The following table presents our target allocations for 2013 and our pension and postretirement plans’ asset categories as of December 31, 2012, and 2011.
Asset
Category
Target Allocation
2013
 
Percentage of Plan Assets at December  31,
2012
 
2011
Pension Plan:
 
 
 
 
 
Cash and cash equivalents
0 - 5  %
 
2
%
 
2
%
Equity securities:
 
 
 
 
 
U.S. large capitalization
29 - 39
 
34

 
33
%
U.S. small and mid-capitalization
2 - 12
 
7

 
7
%
International and emerging markets
9 - 19
 
13

 
11
%
Total equity
50 - 60
 
54

 
51
%
Debt securities
35 - 45
 
39

 
42
%
Real estate
0 -   9  
 
4

 
4
%
Private equity
0 -   4  
 
1

 
1
%
Total
 
 
100
%
 
100
%
Postretirement Plans:
 
 
 
 
 
Cash and cash equivalents
0 - 10 %
 
4
%
 
4
%
Equity securities:
 
 
 
 
 
U.S. large capitalization
33 - 43
 
40
%
 
38
%
U.S. small and mid-capitalization
3 - 13
 
8
%
 
8
%
International
10 - 20
 
14
%
 
13
%
Total equity
55 - 65
 
62
%
 
59
%
Debt securities
30 - 40
 
34
%
 
37
%
Total
 
 
100
%
 
100
%
Changes In The Fair Value Of Plan Assets Classified As Level 3 
The following table summarizes the changes in the fair value of the pension plan assets classified as Level 3 in the fair value hierarchy for each of the years ended December 31, 2012, and 2011:
 
Beginning
Balance at
January 1,
 
Actual Return on
Plan Assets Related
to Assets Still Held
at the Reporting Date
 
Actual Return on
Plan Assets Related
to Assets Sold
During the Period
 
Purchases,
Sales, and
Settlements, net
 
Net
Transfers
into (out of)
of Level 3
 
Ending Balance at
December 31,
2012:
 
 
 
 
 
 
 
 
 
 
 
Real estate
$
108

 
$
7

 
$
—

 
$
3

 
$
—

 
$
118

Private equity
23

 
(7
)
 
8

 
(5
)
 
—

 
19

2011:
 
 
 
 
 
 
 
 
 
 
 
Real estate
$
98

 
$
10

 
$
—

 
$
—

 
$
—

 
$
108

Private equity
28

 
(10
)
 
11

 
(6
)
 
—

 
23

Components Of Net Periodic Benefit Cost 
The following table presents the components of the net periodic benefit cost of our pension and postretirement benefit plans during 2012, 2011, and 2010:
 
Pension Benefits
 
Postretirement Benefits
2012
 
 
 
Service cost
$
81

 
$
22

Interest cost
166

 
47

Expected return on plan assets
(208
)
 
(56
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
(3
)
 
(6
)
Actuarial loss
75

 
5

Net periodic benefit cost
$
111

 
$
14

2011
 
 
 
Service cost
$
73

 
$
20

Interest cost
175

 
54

Expected return on plan assets
(211
)
 
(50
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
(1
)
 
(6
)
Actuarial loss
41

 
3

Net periodic benefit cost
$
77

 
$
23

2010
 
 
 
Service cost
$
65

 
$
18

Interest cost
181

 
58

Expected return on plan assets
(208
)
 
(51
)
Amortization of:
 
 
 
Transition obligation
—

 
2

Prior service cost
6

 
(6
)
Actuarial loss
18

 
—

Net periodic benefit cost
$
62

 
$
21

Summary Of Estimated Amortizable Amounts From Regulatory Assets and Accumulated OCI Into Net Periodic Benefit Cost 
The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in 2013 are as follows:
  
Pension Benefits
 
Postretirement Benefits
  
Ameren
 
Ameren
Regulatory assets:
 
 
 
Prior service cost (credit)
$
(1
)
 
$
(4
)
Net actuarial loss
97

 
19

Accumulated OCI:
 
 
 
Prior service cost (credit)
(2
)
 
(1
)
Net actuarial loss
5

 
—

Total
$
99

 
$
14

Schedule Of Expected Payments From Qualified Trust And Company Funds 
The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, as of December 31, 2012, are as follows:
  
Pension Benefits
 
Postretirement Benefits
  
Paid from
Qualified
Trust
 
Paid from
Company
Funds
 
Paid from
Qualified
Trust
 
Paid from
Company
Funds
 
Federal
Subsidy
2013
$
229

 
$
3

 
$
58

 
$
2

 
$
3

2014
236

 
3

 
60

 
2

 
3

2015
239

 
3

 
62

 
2

 
4

2016
245

 
3

 
65

 
2

 
4

2017
248

 
3

 
68

 
2

 
4

2018 - 2022
1,279

 
13

 
384

 
11

 
19

Assumptions Used To Determine Net Periodic Benefit Cost 
The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2012, 2011, and 2010:
  
Pension Benefits
 
Postretirement Benefits
  
2012
 
2011
 
2010
 
2012
 
2011
 
2010
Discount rate at measurement date
4.50
%
 
5.25
%
 
5.75
%
 
4.50
%
 
5.25
%
 
5.75
%
Expected return on plan assets
7.75

 
8.00

 
8.00

 
7.50

 
7.75

 
8.00

Increase in future compensation
3.50

 
3.50

 
3.50

 
3.50

 
3.50

 
3.50

Medical cost trend rate (initial)
—

 
—

 
—

 
5.50

 
6.00

 
6.50

Medical cost trend rate (ultimate)
—

 
—

 
—

 
5.00

 
5.00

 
5.00

Years to ultimate rate
0

 
0

 
0

 
1 year

 
2 years

 
3 years

Schedule Of Potential Changes In Key Assumptions 
The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:
  
Pension Benefits
 
Postretirement Benefits
  
Service Cost
and Interest
Cost
 
Projected
Benefit
Obligation
 
Service Cost
and Interest
Cost
 
Postretirement
Benefit
Obligation
0.25% decrease in discount rate
$
(2
)
 
$
121

 
$
—

 
$
34

0.25% increase in salary scale
2

 
13

 
—

 
—

1.00% increase in annual medical trend
—

 
—

 
—

 
36

1.00% decrease in annual medical trend
—

 
—

 
(1
)
 
(34
)
Target Allocation Of The Plans' Asset Categories 
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2012:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
1

 
$
28

 
$
—

 
$
29

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
83

 
1,007

 
—

 
1,090

U.S. small and mid-capitalization
235

 
—

 
—

 
235

International and emerging markets
134

 
301

 
—

 
435

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
832

 
—

 
832

Municipal bonds
—

 
176

 
—

 
176

U.S. treasury and agency securities
—

 
250

 
—

 
250

Other
—

 
17

 
—

 
17

Real estate
—

 
—

 
118

 
118

Private equity
—

 
—

 
19

 
19

Derivative assets
—

 
—

 
—

 
—

Derivative liabilities
(1
)
 
—

 
—

 
(1
)
Total
$
452

 
$
2,611

 
$
137

 
$
3,200

Less: Medical benefit assets at December 31(a)
 
 
 
 
 
 
(102
)
Plus: Net receivables at December 31(b)
 
 
 
 
 
 
29

Fair value of pension plans assets at year end
 
 
 
 
 
 
$
3,127

(a)
Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation.
(b)
Receivables related to pending security sales, offset by payables related to pending security purchases.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the pension plan assets measured at fair value as of December 31, 2011:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
—

 
$
30

 
$
—

 
$
30

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
72

 
901

 
—

 
973

U.S. small and mid-capitalization
202

 
—

 
—

 
202

International and emerging markets
115

 
208

 
—

 
323

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
794

 
—

 
794

Municipal bonds
—

 
176

 
—

 
176

U.S. treasury and agency securities
—

 
230

 
—

 
230

Other
—

 
23

 
—

 
23

Real estate
—

 
—

 
108

 
108

Private equity
—

 
—

 
23

 
23

Derivative assets
1

 
—

 
—

 
1

Derivative liabilities
(1
)
 
—

 
—

 
(1
)
Total
$
389

 
$
2,362

 
$
131

 
$
2,882

Less: Medical benefit assets at December 31(a)
 
 
 
 
 
 
(91
)
Plus: Net receivables at December 31(b)
 
 
 
 
 
 
23

Fair value of pension plans assets at year end
 
 
 
 
 
 
$
2,814

(a)
Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation.
(b)
Receivables related to pending security sales, offset by payables related to pending security purchases.
Target Allocation Of The Plans' Asset Categories 
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2012:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
83

 
$
—

 
$
—

 
$
83

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
245

 
88

 
—

 
333

U.S. small and mid-capitalization
66

 
—

 
—

 
66

International
45

 
69

 
—

 
114

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
88

 
—

 
88

Municipal bonds
—

 
91

 
—

 
91

U.S. treasury and agency securities
—

 
67

 
—

 
67

Asset-backed securities
—

 
18

 
—

 
18

Other
—

 
22

 
—

 
22

Total
$
439

 
$
443

 
$
—

 
$
882

Plus: Medical benefit assets at December 31(a)
 
 
 
 
 
 
102

Less: Net payables at December 31(b)
 
 
 
 
 
 
(46
)
Fair value of postretirement benefit plans assets at year end
 
 
 
 
 
 
$
938

(a)
Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.
(b)
Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.
The following table sets forth, by level within the fair value hierarchy discussed in Note 8 - Fair Value Measurements, the postretirement benefit plans assets measured at fair value as of December 31, 2011:
 
Quoted Prices in
Active Markets for
Identified Assets
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Cash and cash equivalents
$
1

 
$
65

 
$
—

 
$
66

Equity securities:
 
 
 
 
 
 
 
U.S. large capitalization
206

 
78

 
—

 
284

U.S. small and mid-capitalization
57

 
—

 
—

 
57

International
38

 
56

 
—

 
94

Debt securities:
 
 
 
 
 
 
 
Corporate bonds
—

 
71

 
—

 
71

Municipal bonds
—

 
80

 
—

 
80

U.S. treasury and agency securities
—

 
69

 
—

 
69

Asset-backed securities
—

 
23

 
—

 
23

Other
—

 
34

 
—

 
34

Total
$
302

 
$
476

 
$
—

 
$
778

Plus: Medical benefit assets at December 31(a)
 
 
 
 
 
 
91

Less: Net payables at December 31(b)
 
 
 
 
 
 
(33
)
Fair value of postretirement benefit plans assets at year end
 
 
 
 
 
 
$
836

(a)
Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above.
(b)
Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales.
Stock-Based Compensation (Tables)
Summary Of Nonvested Shares Related To Long-Term Incentive Plan
A summary of nonvested shares at December 31, 2012, and changes during the year ended December 31, 2012, under the 2006 Plan are presented below:
  
Performance Share Units
  
Share
Units
 
Weighted-average
Fair Value per Unit
Nonvested at January 1, 2012
1,156,831

 
$
31.70

Granted(a)
717,151

 
35.68

Unearned or forfeited(b)
(477,928
)
 
32.04

Earned and vested(c)
(203,567
)
 
34.01

Nonvested at December 31, 2012
1,192,487

 
$
33.56

(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b)
Includes share units granted in 2010 that were not earned based on performance provisions of the award grants.
(c)
Includes share units granted in 2010 that vested as of December 31, 2012, that were earned pursuant to the provisions of the award grants. Also includes share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.
Income Taxes (Tables)
Schedule Of Effective Income Tax Rate Reconciliation 
The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2012, 2011, and 2010:
 
2012
2011
2010
Statutory federal income tax rate:
35
 %
35
 %
35
 %
Increases (decreases) from:
 
 
 
Depreciation differences
(1
)
(1
)
(3
)
Amortization of investment tax credit
(1
)
(1
)
(1
)
State tax
5

4

5

Reserve for uncertain tax positions
—

1

(1
)
Tax credits
—

(1
)
(1
)
Change in federal tax law(a)
—

—

2

Other permanent items(b)
(1
)
—

—

Effective income tax rate
37
 %
37
 %
36
 %
(a)
Relates to change in taxation of prescription drug benefits to retiree participants from the enactment in 2010 of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010.
(b)
Permanent items are treated differently for book and tax purposes and primarily include nondeductible expense related to lobbying and stock issuance expenses.
Schedule Of Components Of Income Tax Expense (Benefit) 
The following table presents the components of income tax expense for the years ended December 31, 2012, 2011, and 2010:
 
2012
2011
2010
Current taxes:
 
 
 
Federal
$
40

$
(6
)
$
3

State
9

(2
)
(1
)
Deferred taxes:
 
 
 
Federal
205

206

247

State
61

53

32

Deferred investment tax credits, amortization
(6
)
(6
)
(7
)
Total income tax expense
$
309

$
245

$
274


Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences 
The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2012, and 2011:
 
2012
2011
Accumulated deferred income taxes, net liability (asset):
 
 
Plant related
$
3,512

$
3,162

Deferred intercompany tax gain/basis step-up
39

54

Regulatory assets, net
73

73

Deferred employee benefit costs
(323
)
(320
)
Purchase accounting
(27
)
(28
)
ARO
(17
)
(12
)
Other(a)
(251
)
(217
)
Total net accumulated deferred income tax liabilities
$
3,006

$
2,712

(a)
Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below.
Schedule Of Net Operating Loss Carryforwards And Tax Credit Carryforwards 
The following table presents the components of deferred tax assets relating to net operating loss carryforwards and tax credit carryforwards at December 31, 2012:
 
2012
Net operating loss carryforwards:
 
Federal(a)
$
173

State(b)
27

Total net operating loss carryforwards
$
200

Tax credit carryforwards:
 
Federal(c)
$
86

State(d)
25

State valuation allowance(e)
(2
)
Total tax credit carryforwards
$
109

(a)
These will begin to expire in 2028.
(b)
These will begin to expire in 2017.
(c)
These will begin to expire in 2029.
(d)
These will begin to expire in 2013.
(e)
This balance increased by $1 million during 2012.
Schedule Of Changes To Unrecognized Tax Benefits And Related Interest 
A reconciliation of the change in the unrecognized tax benefit balance during the years ended December 31, 2012, 2011, and 2010, is as follows:
 
2012
2011
2010
Unrecognized tax benefits - beginning of year
$
148

$
246

$
135

Increases based on tax positions prior to current year
5

22

72

Decreases based on tax positions prior to current year
(13
)
(125
)
(38
)
Increases based on tax positions related to current year
17

17

77

Changes related to settlements with taxing authorities
—

(10
)
—

Decreases related to the lapse of statute of limitations
(1
)
(2
)
—

Unrecognized tax benefits - end of year
$
156

$
148

$
246

Total unrecognized tax benefits that, if recognized, would affect the effective tax rates
$
1

$
1

$
—

Reconciliation Of Changes In Liability For Interest On Unrecognized Tax Benefits 
A reconciliation of the change in the liability for interest on unrecognized tax benefits during the years ended December 31, 2012, 2011, and 2010, is as follows:
 
2012
2011
2010
Liability for interest - beginning of year
$
5

$
17

$
8

Interest charges (income)
1

(11
)
9

Interest payment
—

(1
)
—

Liability for interest - end of year
$
6

$
5

$
17

Related Party Transactions (Tables)
Schedule of Related Party Transactions [Table Text Block]
The related party transactions discussed above, with the exception of Genco's land sale to ATXI and the parent company guarantees, are eliminated in Ameren's consolidated financial statements. Ameren will have continuing transactions with New AER after the divestiture is complete that will not be eliminated in Ameren's consolidated financial statements. The following table presents the impact of these related party transactions, primarily based on the agreements discussed above, for the years ended December 31, 2012, 2011, and 2010.
Agreement
Income Statement Line Item                    
 
  
 
Amount
Ameren Missouri and Genco gas
Operating Revenues
 
2012
 
$
1

transportation agreement
 
 
2011
 
1

 
 
 
2010
 
1

Ameren Illinois and ATXI transmission services agreement
Operating Revenues
 
2012
 
16

with Marketing Company
 
 
2011
 
11

 
 
 
2010
 
10

Total Operating Revenues
 
 
2012
 
$
17

 
 
 
2011
 
12

 
 
 
2010
 
11

Ameren Illinois power supply agreements
Purchased Power
 
2012
 
$
311

with Marketing Company
 
 
2011
 
232

 
 
 
2010
 
233

Ameren Illinois gas purchases from Genco
Gas Purchased for Resale
 
2012
 
$
—

 
 
 
2011
 
—

 
 
 
2010
 
1

Commitments And Contingencies (Tables)
Schedule Of Insurance Coverage At Callaway Energy Center 
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at December 31, 2012. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.
Type and Source of Coverage
Maximum Coverages
 
Maximum Assessments
 
Public liability and nuclear worker liability:
 
 
 
 
American Nuclear Insurers
$
375


$
—

 
Pool participation
12,219

(a)  
118

(b)  
 
$
12,594

(c)  
$
118

 
Property damage:
 
 
 
 
Nuclear Electric Insurance Ltd.
$
2,750

(d)  
$
23

(e)  
Replacement power:
 
 
 
 
Nuclear Electric Insurance Ltd
$
490

(f)  
$
9

(e)  
Energy Risk Assurance Company
$
64

(g)  
$
—

 

(a)
Provided through mandatory participation in an industrywide retrospective premium assessment program.
(b)
Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c)
Limit of liability for each incident under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d)
Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(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)
Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(g)
Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 - Related Party Transactions with New AER for more information on this affiliate transaction.
Schedule Of Lease Obligations 
We lease various facilities, office equipment, plant equipment, and rail cars under capital and operating leases. The following table presents our lease obligations at December 31, 2012:
 
Total
 
2013
 
2014
 
2015
 
2016
 
2017
 
After 5 Years
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital lease payments(a)
$
588

 
$
32

 
$
32

 
$
33

 
$
33

 
$
33

 
$
425

Less amount representing interest
284

 
27

 
27

 
27

 
27

 
27

 
149

Present value of minimum capital lease payments
$
304

 
$
5

 
$
5

 
$
6

 
$
6

 
$
6

 
$
276

Operating leases(b)
138

 
19

 
14

 
14

 
14

 
14

 
63

Total lease obligations
$
442

 
$
24

 
$
19

 
$
20

 
$
20

 
$
20

 
$
339


(a)
See Properties under Part I, Item 2, and Note 3 - Property and Plant, Net of this report for additional information.
(b)
Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million for these items is included in the 2013 through 2017 columns, respectively.
Schedule Of Estimated Purchased Commitments 
The table below presents our estimated fuel, purchased power, and other commitments at December 31, 2012. Ameren’s purchased power obligations include Ameren Missouri's 102-megawatt power purchase agreement with a wind farm operator that expires in 2024 and the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services at December 31, 2012, obligations related to IEIMA for Ameren Illinois, and obligations related to energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order for Ameren Missouri. The order provides that, beginning in 2013, Ameren Missouri will invest approximately $147 million over three years for energy efficiency programs. See Note 2 - Rate and Regulatory Matters for additional information about the IEIMA and MEEIA.
 
Coal
 
Natural
Gas
 
Nuclear
Fuel
 
Purchased
Power(a)
 
Methane
Gas
 
Other
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013
$
620

 
$
327

 
$
36

 
$
421

 
$
3

 
$
156

 
$
1,563

2014
625

 
249

 
89

 
309

 
3

 
159

 
1,434

2015
614

 
136

 
87

 
164

 
4

 
117

 
1,122

2016
644

 
54

 
95

 
78

 
4

 
62

 
937

2017
676

 
34

 
78

 
55

 
5

 
50

 
898

Thereafter
245

 
105

 
277

 
687

 
99

 
246

 
1,659

Total
$
3,424

 
$
905

 
$
662

 
$
1,714

 
$
118

 
$
790

 
$
7,613

(a)
The purchased power amounts includes Ameren Illinois' 20-year agreements for renewable energy credits that were entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.
Schedule Of Estimated Capital Costs To Comply With Existing And Known Emissions Related Regulations 
Continuing Operations:
  
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.
Discontinued Operations:
  
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 the construction of two scrubbers at the Newton energy center.
(b)
Assumes the Merchant Generation facilities are owned by Ameren.
  
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 the construction of two scrubbers at the Newton energy center.
(b)
Assumes the Merchant Generation facilities are owned by Ameren.
Schedule Of Estimated Obligations For Manufactured Gas Plant Remediation 
The following table presents, as of December 31, 2012, the estimated probable obligation to remediate these former MGP sites.
  
Estimate
 
Recorded
Liability(a)
 
Low
 
High
 
 
$
257

 
$
339

 
$
257

(a)
Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.
Schedule Of Asbestos-Related Litigation Pending Lawsuits 
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31, 2012:
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Total(a)
4
 
74
 
96
 
121
(a)
Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
Divestiture Transactions and Discontinued Operations (Tables)
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures 
The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at December 31, 2012 and 2011:
 
December 31, 2012
 
December 31, 2011
Current assets of discontinued operations
 
 
 
Cash and cash equivalents
$
25

 
$
7

Accounts receivable and unbilled revenue
102

 
108

Materials and supplies
134

 
162

Mark-to-market derivative assets
102

 
65

Property and plant, net
748

 
3,279

Accumulated deferred income taxes, net
385

 
—

Other assets
104

 
97

Total current assets of discontinued operations
$
1,600

 
$
3,718

Current liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
$
133

 
$
134

Mark-to-market derivative liabilities
63

 
39

Long-term debt, net
824

 
824

Accumulated deferred income taxes, net
—

 
583

Asset retirement obligations
78

 
64

Pension and other postretirement benefits
40

 
92

Other liabilities
28

 
26

Total current liabilities of discontinued operations
$
1,166

 
$
1,762

Accumulated other comprehensive income (loss)(a)
$
19

 
$
(31
)
Noncontrolling interest(b)
$
8

 
$
7

(a)
Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s December 31, 2012 and 2011, consolidated balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s consolidated balance sheet either before or at the closing of the New AER divestiture.
(b)
The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s December 31, 2012 and 2011, consolidated balance sheets. This noncontrolling interest will be removed from Ameren’s consolidated balance sheet at the closing of the New AER divestiture.
The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the year ended December 31, 2012, 2011 and 2010:
 
Year ended
 
 
2012
 
2011
 
2010
 
Operating revenues
$
1,047

 
$
1,278

 
$
1,369

 
Operating expenses
(3,478
)
(a) 
(1,048
)
 
(1,578
)
(b) 
Operating income (loss)
(2,431
)
 
230

 
(209
)
 
Other income (loss)
—

 
1

 
2

 
Interest charges
(56
)
 
(64
)
 
(83
)
 
Income (loss) before income taxes
(2,487
)
 
167

 
(290
)
 
Income tax (expense) benefit
989

 
(65
)
 
(51
)
 
Income (loss) from discontinued operations, net of taxes
$
(1,498
)
 
$
102

 
$
(341
)
 
(a)
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. In addition, includes a noncash pretax asset impairment charge of $1.95 billion to reduce the carrying values of all the AER coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values, under held and used accounting guidance, as a result of the decision in December 2012 that Ameren intends to exit the Merchant Generation business.
(b)
Includes a noncash pretax goodwill impairment charge of $420 million representing all the goodwill assigned to Ameren's Merchant Generation reporting unit as a result of proposed and pending environmental regulations which were expected to result in a significant increase in capital and operations and maintenance expenditures for the energy centers held by AER. Also, includes a $36 million noncash pretax asset impairment charge to reduce the carrying value of the Medina Valley energy center to its estimated fair value and a noncash pretax intangible asset impairment charge of $68 million to reduce existing SO2 emission allowances to their estimated fair value.
Schedule Of Coverage Ratios 
The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable as of December 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.
 
Required Interest
Coverage Ratio(a)
Actual Interest
Coverage Ratio
Bonds Issuable(b)
 
Required Dividend
Coverage Ratio(c)
Actual Dividend
Coverage Ratio
Preferred Stock
Issuable
Ameren Missouri
          >2.0
4.6

$
4,056

  
>2.5
122.8

$
2,351

Ameren Illinois
          >2.0
7.1

3,439

(d) 
>1.5
2.8

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.
Schedule Of Coverage Ratios 
The following table summarizes these ratios for the 12 months ended and as of December 31, 2012:
  
Required
Ratio
Actual
Ratio
Interest coverage ratio- restricted payment (a)
≥1.75
2.6

Interest coverage ratio- additional indebtedness (b)
≥2.50
2.6

Debt-to-capital ratio- additional indebtedness (b)
≤60%
44
%
(a)
As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
(b)
Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.
Impairment and Other Charges (Tables)
Impairment Charges
The following table summarizes the pretax charges recorded in the consolidated statement of income (loss) as “Impairment and other charges” for the years ended December 31, 2012, 2011, and 2010:
 
2012
2011
2010
Long-Lived Assets and Related Charges
$
—

$
123

$
64


Segment Information (Tables)
Schedule Of Segment Reporting Information, By Segment
The following table presents information about the reported revenues and specified items reflected in net income attributable to Ameren Corporation from continuing operations for the years ended December 31, 2012, 2011, and 2010, and total assets as of December 31, 2012, 2011, and 2010.
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Other
 
Intersegment
Eliminations
 
Consolidated
 
2012
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,252

 
$
2,524

 
$
5

 
$
—

 
$
5,781

 
Intersegment revenues
20

 
1

 
3

 
(24
)
 
—

 
Depreciation and amortization
440

 
221

 
6

 
—

 
667

 
Interest and dividend income
32

 
—

 
—

 
—

 
32

 
Interest charges
223

 
129

 
39

 
—

 
391

 
Income taxes (benefit)
252

 
94

 
(37
)
 
—

 
309

 
Net income (loss) attributable to Ameren Corporation from continuing operations
416

 
141

 
(39
)
 
—

 
518

 
Capital expenditures
595

 
442

 
26

 
—

 
1,063

 
Total assets
13,043

 
7,282

 
1,228

 
(934
)
 
20,619

(a) 
2011
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,360

 
$
2,784

 
$
83

 
$
—

 
$
6,227

 
Intersegment revenues
23

 
3

 
3

 
(29
)
 
—

 
Depreciation and amortization
408

 
215

 
23

 
—

 
646

 
Interest and dividend income
30

 
1

 
—

 
—

 
31

 
Interest charges
209

 
136

 
42

 
—

 
387

 
Income taxes (benefit)
161

 
127

 
(43
)
 
—

 
245

 
Net income (loss) attributable to Ameren Corporation from continuing operations
287

 
193

 
(62
)
 
—

 
418

 
Capital expenditures
550

 
351

 
(20
)
(b) 
—

 
881

 
Total assets
12,757

 
7,213

 
1,211

 
(1,176
)
 
20,005

(a) 
2010
 
 
 
 
 
 
 
 
 
 
External revenues
$
3,180

 
$
3,012

 
$
77

 
$
—

 
$
6,269

 
Intersegment revenues
17

 
2

 
—

 
(19
)
 
—

 
Depreciation and amortization
382

 
210

 
35

 
—

 
627

 
Interest and dividend income
31

 
1

 
—

 
—

 
32

 
Interest charges
213

 
143

 
59

 
—

 
415

 
Income taxes (benefit)
199

 
137

 
(62
)
 
—

 
274

 
Net income (loss) attributable to Ameren Corporation from continuing operations
364

 
208

 
(89
)
 
—

 
483

 
Capital expenditures
624

 
281

 
36

 
—

 
941

 
Total assets
12,504

 
7,406

 
1,354

 
(1,541
)
 
19,723

(a) 
(a)
Excludes "Current assets for discontinued operations." See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.
(b)
Includes the elimination of intercompany transfers.
Selected Quarterly Information (Tables)
Summary Of Selected Quarterly Information
 
 
2012
 
 
2011
Quarter ended (a)
 
March 31
 
June 30
 
September 30
 
December 31
 
 
March 31
 
June 30
 
September 30
 
December 31
Operating Revenues
 
$
1,412

 
$
1,402

 
$
1,709

 
$
1,258

 
 
$
1,597

 
$
1,458

 
$
1,876

 
$
1,296

Operating Income (b)
 
158

 
344

 
578

 
111

 
 
156

 
270

 
494

 
91

Net Income (Loss)
 
(403
)
 
210

 
374

 
(1,155
)
 
 
74

 
139

 
287

 
26

Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations
 
$
37

 
$
161

 
$
305

 
$
15

 
 
$
38

 
$
116

 
$
265

 
$
(1
)
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations (c)
 
(440
)
 
50

 
69

 
(1,171
)
 
 
33

 
22

 
20

 
26

Net Income (Loss) Attributable to Ameren Corporation
 
$
(403
)
 
$
211

 
$
374

 
$
(1,156
)
 
 
$
71

 
$
138

 
$
285

 
$
25

Earnings (Loss) per Common Share - Basic and Diluted - Continuing Operations
 
$
0.15

 
$
0.66

 
$
1.26

 
$
0.06

 
 
$
0.16

 
$
0.48

 
$
1.10

 
$
(0.01
)
Earnings (Loss) per Common Share - Basic and Diluted - Discontinued Operations
 
(1.81
)
 
0.21

 
0.28

 
(4.82
)
 
 
0.13

 
0.09

 
0.08

 
0.11

Earnings (Loss) per Common Share - Basic and Diluted
 
$
(1.66
)
 
$
0.87

 
$
1.54

 
$
(4.76
)
 
 
$
0.29

 
$
0.57

 
$
1.18

 
$
0.10

(a)
The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding and changes in the number of weighted-average shares outstanding each period.
(b)
Includes pretax "Impairment and other charges" of $123 million recorded to continuing operations during the year ended December 31, 2011. See Note 17 - Impairment and Other Charges for additional information.
(c)
Includes a pretax asset impairment charge of $2.578 billion recorded to discontinued operations during the year ended December 31, 2012. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information.
Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 0 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Ameren Illinois Company [Member]
sqmi
people
Dec. 31, 2012
Union Electric Company [Member]
sqmi
people
Dec. 31, 2012
Electric Energy Inc [Member]
Mar. 14, 2013
Ameren Energy Generating Company [Member]
Dec. 31, 2011
Shutdown Of Meredosia And Hutsonville Energy Centers [Member]
Dec. 31, 2012
Voluntary Separation Offer [Member]
Dec. 31, 2011
SO2 Emission Allowances [Member]
Dec. 31, 2012
Minimum [Member]
Dec. 31, 2011
Minimum [Member]
Dec. 31, 2010
Minimum [Member]
Dec. 31, 2012
Maximum [Member]
Dec. 31, 2011
Maximum [Member]
Dec. 31, 2010
Maximum [Member]
Dec. 31, 2012
Power [Member]
Ameren Illinois Company [Member]
customer
Dec. 31, 2012
Power [Member]
Union Electric Company [Member]
customer
Dec. 31, 2012
Natural Gas [Member]
Ameren Illinois Company [Member]
customer
Dec. 31, 2012
Natural Gas [Member]
Union Electric Company [Member]
customer
Dec. 31, 2012
FAC [Member]
Union Electric Company [Member]
Accounting Policies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public utilities, Area serviced
 
 
 
40,000 
24,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public utilities, Estimated population of service territory
 
 
 
3,100,000 
2,800,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Public uitilities, Number of customers
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,200,000 
1,200,000 
806,000 
127,000 
 
Ownership percentage by parent
 
 
 
 
 
80.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Initial payment received
    
$ 3 
$ 7 
 
 
 
$ 100 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percent of average depreciable cost
 
 
 
 
 
 
 
 
 
 
3.00% 
3.00% 
3.00% 
4.00% 
4.00% 
4.00% 
 
 
 
 
 
Allowance for funds used during construction, rate
 
 
 
 
 
 
 
 
 
 
8.00% 
8.00% 
8.00% 
9.00% 
9.00% 
9.00% 
 
 
 
 
 
Book value
14 
7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization expense
4 
3 
13 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pretax impairment charge
 
 
 
 
 
 
 
 
 
1 
 
 
 
 
 
 
 
 
 
 
 
Sharing level for FAC
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
95.00% 
Excise tax expense
193 
194 
189 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Tax grants received related to renewable energy properties
18 
   
   
 
18 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of EEI not owned by Ameren
 
 
 
 
 
20.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of employee positions eliminated
 
 
 
 
 
 
 
 
340 
 
 
 
 
 
 
 
 
 
 
 
 
Severance costs
 
 
 
 
 
 
 
$ 4 
$ 28 
 
 
 
 
 
 
 
 
 
 
 
 
Summary Of Significant Accounting Policies (Schedule Of Material And Supplies) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Accounting Policies [Abstract]
 
 
Fuel
$ 198 1
$ 150 1
Gas stored underground
131 
171 
Other materials and supplies
241 
229 
Total materials and supplies
$ 570 
$ 550 
Summary Of Significant Accounting Policies (Schedule Of Asset Retirement Obligations) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
 
 
Balance, beginning of year
$ 369 1 2
$ 403 1
Liabilities incurred
   1
   1
Liabilities settled
(6)1
(2)1
Accretion in period
20 1 3
22 1 3
Change in estimates
(8)1 4
(54)1 5
Balance, end of year
375 1
369 1 2
Nuclear decommissioning trust fund
408 
357 
Asset retirement obligation included in other current liabilities
 
$ 5 
Rate And Regulatory Matters (Narrative) (Details) (USD $)
1 Months Ended 12 Months Ended 1 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 60 Months Ended 0 Months Ended 3 Months Ended 3 Months Ended 3 Months Ended 1 Months Ended 1 Months Ended 12 Months Ended 1 Months Ended
Nov. 30, 2012
design
Dec. 31, 2012
design
Dec. 31, 2011
Dec. 31, 2010
Jun. 30, 2008
FERC Relicensing [Member]
Taum Sauk Energy Center [Member]
Dec. 31, 2012
Union Electric Company [Member]
New Nuclear Energy Center COL [Member]
Apr. 30, 2011
Union Electric Company [Member]
FAC Prudence Review [Member]
Dec. 31, 2012
Union Electric Company [Member]
FAC Prudence Review [Member]
Feb. 29, 2012
Union Electric Company [Member]
FAC Prudence Review [Member]
Dec. 31, 2012
Union Electric Company [Member]
Entergy Refund [Member]
Dec. 31, 2005
Union Electric Company [Member]
Pending FERC Case [Member]
Power Purchase Agreement With Entergy Arkansas [Member]
Jul. 13, 2011
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Dec. 31, 2012
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
May 31, 2010
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
account
Jan. 31, 2009
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Dec. 31, 2012
Union Electric Company [Member]
Final Rate Order [Member]
MEEIA [Member]
Electric Distribution [Member]
Jul. 13, 2011
Union Electric Company [Member]
Accounting Authority Order Request [Member]
FAC Prudence Review [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
customer
Dec. 31, 2012
Ameren Illinois Company [Member]
Wholesale Distribution Rate Case [Member]
Jan. 31, 2011
Ameren Illinois Company [Member]
Wholesale Distribution Rate Case [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
IEIMA [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
IEIMA [Member]
Smart Grid [Member]
Mar. 31, 2013
Ameren Illinois Company [Member]
Final Rate Order [Member]
IEIMA [Member]
Electric Distribution [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
Final Rate Order [Member]
IEIMA [Member]
Electric Distribution [Member]
Jan. 31, 2013
Ameren Illinois Company [Member]
Pending Rate Case [Member]
Gas Distribution [Member]
Dec. 31, 2012
ATXI [Member]
Potential Transmission Project Investments Through 2019 [Member]
project
Dec. 31, 2012
Energy Infrastructure Investments and Other Nonfuel Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Dec. 31, 2012
Pension and Other Post-Employment Benefit Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Dec. 31, 2012
Amortization of Regulatory Asset [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Dec. 31, 2012
Net Base Fuel Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Jul. 13, 2011
Net Base Fuel Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Dec. 31, 2012
FAC [Member]
Union Electric Company [Member]
Dec. 31, 2012
Maximum [Member]
Union Electric Company [Member]
New Nuclear Energy Center COL [Member]
Jan. 31, 2013
Maximum [Member]
Ameren Illinois Company [Member]
Pending Rate Case [Member]
Gas Distribution [Member]
Dec. 31, 2012
Minimum [Member]
Union Electric Company [Member]
New Nuclear Energy Center COL [Member]
Jan. 31, 2013
Minimum [Member]
Ameren Illinois Company [Member]
Pending Rate Case [Member]
Gas Distribution [Member]
Dec. 31, 2012
Pending FERC Case [Member]
Ameren Illinois Company [Member]
customer
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$ 184,000,000 
$ 248,000,000 
$ 538,000,000 
 
 
 
 
 
 
 
 
 
$ 16,000,000 
$ 21,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Disallowed capitalized costs associated with rebuilt Taum Sauk energy center
 
 
 
 
 
 
 
 
 
 
 
89,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorized increase in revenue from utility service
 
 
 
 
 
 
 
 
 
 
 
173,000,000 
260,000,000 
230,000,000 
 
80,000,000 
 
 
 
 
 
 
 
 
 
 
96,000,000 
10,000,000 
6,000,000 
84,000,000 
52,000,000 
 
 
 
 
 
 
Number of industrial customers who received a stay from Circuit Court
 
 
 
 
 
 
 
 
 
 
 
 
 
4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility revenue increase requested
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11,000,000 
 
 
 
 
50,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Contingency, Settlement Agreement, Number of Wholesale Customers
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4 
Number of Wholesale Customers
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5 
Rate of return on common equity
 
 
 
 
 
 
 
 
 
 
 
 
9.80% 
 
 
 
 
 
 
 
 
 
 
 
10.40% 
 
 
 
 
 
 
 
 
 
 
 
 
Percent of capital structure composed of equity
 
 
 
 
 
 
 
 
 
 
 
 
52.30% 
 
 
 
 
 
 
 
 
 
 
 
51.80% 
 
 
 
 
 
 
 
 
 
 
 
 
Rate base
 
 
 
 
 
 
 
 
 
 
 
 
6,800,000,000 
 
 
 
 
 
 
 
 
 
 
 
1,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Fixed non-volumetric customer charge
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
85.00% 
 
80.00% 
 
Investments in Power and Distribution Projects, Number of Projects
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
 
 
 
 
 
 
 
 
 
 
Energy Efficiency program spending
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
147,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of years approved
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
 
10 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Percentage of Project Lost Revenue Included in Rates
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
90.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Remaining Percentage of Projected Lost Revenue
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Incentive Award if Energy Efficiency Goals Are Achieved
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
19,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Achieved Percentage of Energy Efficiency Earnings For Incentive Award
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Incentive Award if Energy Efficiency Goals Are Achieved, Period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum Percentage of Energy Efficiency Goal Achievement For Company To Be Eligible For Incentive Award
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
70.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sharing level for FAC
 
 
 
 
 
 
 
 
 
 
 
 
95.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
95.00% 
 
 
 
 
 
Revenue requirement transferred from net fuel cost to other nonfuel costs
 
 
 
 
 
 
 
 
 
 
 
 
33,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Request to defer fixed costs not recovered from Noranda, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
36,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue Requirement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
779,000,000 
764,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authorized Decrease In Revenue From Utility Service
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
55,000,000 
15,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities
 
1,589,000,000 
1,502,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
55,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Time required to complete FAC prudence reviews, in months
 
 
 
 
 
 
 
18 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contested Amounts Under FAC
 
 
 
 
 
 
18,000,000 
 
26,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current regulatory liabilities
 
100,000,000 
133,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from Legal Settlements
 
 
 
 
 
 
 
 
 
31,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchased power
 
780,000,000 
952,000,000 
1,122,000,000 
 
 
 
 
 
24,000,000 
25,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Department of Energy, Investing Funding Support, Period
 
5 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs Awarded
1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Nonoperating Income
 
70,000,000 
68,000,000 
88,000,000 
 
 
 
 
 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Reduction To Under-recovered Asset
 
 
 
 
 
 
 
 
 
2,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number Of Years COL is Valid For
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
40 years 
 
 
Interest Expense
 
391,000,000 
387,000,000 
415,000,000 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital investments
 
 
 
 
 
$ 69,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 360,000,000 
 
 
 
$ 1,300,000,000 
 
 
 
 
 
 
$ 100,000,000 
 
$ 80,000,000 
 
 
Number of years for proposed relicensing application filed with FERC
 
 
 
 
40 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate And Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory assets
$ 247 
$ 215 
Noncurrent regulatory assets
1,786 
1,603 
Current regulatory liabilities
100 
133 
Noncurrent regulatory liabilities
1,589 
1,502 
Under-Recovered FAC [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory assets
145 1 2
83 1 2
Under-Recovered Illinois Electric Power Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory assets
   1 3
4 1 3
Under-Recovered PGA [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory assets
12 1 3
8 1 3
MTM Derivative Losses [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory assets
90 4
120 4 5
Noncurrent regulatory assets
135 4
100 4
Pension And Postretirement Benefit Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
772 6
878 6
Income Taxes [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
235 7
239 7
Noncurrent regulatory liabilities
46 8
48 8
Asset Retirement Obligation [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
5 9
6 9
Noncurrent regulatory liabilities
80 9
29 9
Callaway Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
44 1 10
48 1 10
Unamortized Loss On Reacquired Debt [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
181 1 11
47 1 11
Recoverable Costs Contaminated Facilities [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
248 12
102 12
SO2 Emission Allowances Sale Tracker [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
2 13
6 13
Storm Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
9 14
16 14
Demand-Side Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
73 1 15
70 1 15
Reserve For Workers' Compensation Liabilities [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
12 16
13 16
Bad Debt Rider [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory liabilities
12 17
10 17
Credit Facilities Fees [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
6 16
10 16
Employee Separation Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
2 18
6 18
Common Stock Issuance Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
7 19
10 19
Construction Accounting For Pollution Control Equipment [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
23 1 20
25 1 20
Other [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory assets
32 21
27 21
Noncurrent regulatory liabilities
4 22
2 22
Over-Recovered FAC [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory liabilities
   23
12 23
Over-Recovered Illinois Electric Power Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory liabilities
58 3
64 3
Over-Recovered PGA [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory liabilities
15 3
9 3
MTM Derivative Gains [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory liabilities
19 24
46 24
Noncurrent regulatory liabilities
2 24
82 24
Wholesale Distribution Refund [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Current regulatory liabilities
8 25
2 25
Removal Costs [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory liabilities
1,347 26
1,269 26
Pension And Postretirement Benefit Costs Tracker [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory liabilities
23 27
38 27
Energy Efficiency Rider [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory liabilities
20 28
24 28
IEMA Revenue Requirement Reconciliation [Member]
 
 
Rate And Regulatory Matters [Line Items]
 
 
Noncurrent regulatory liabilities
$ 55 22
    22
[20] The Ameren Illinois total includes Ameren Illinois Merger integration and optimization costs, which are amortized over four years, beginning in January 2012. The Ameren Illinois total includes costs related to delivery service rate cases. The 2012 natural gas rate case costs are being amortized over a two-year period that began in January 2012. The electric rate case costs for the IEIMA initial rate filing are being amortized over a three-year period that began in January 2012. The Ameren Illinois total also includes a portion of the unamortized debt fair value adjustment recorded upon Ameren's acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007. At Ameren Missouri, the balance primarily includes cost associated with the retirement of renewable energy credits and solar rebates to fulfill its renewable energy portfolio requirement. Costs incurred from January 2010 through July 2012 are being amortized over three years, beginning January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case.
Property And Plant, Net (Schedule Of Property And Plant, Net) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
equipment
agreement
Dec. 31, 2011
equipment
agreement
Property, Plant and Equipment [Line Items]
 
 
Property and plant, at original cost
$ 22,796 1
$ 21,849 1
Accumulated depreciation and amortization
8,346 1
7,868 1
Property and plant, before construction work in progress
14,450 1
13,981 1
Property, Plant and Equipment, Net
15,348 1
14,848 1
Number of combustion turbine electric generation equipment under capital lease agreements
2 
2 
Number of capital lease agreements
2 
2 
Capital lease agreements, gross asset value
228 
229 
Total accumulated depreciation, capital lease agreements
52 
52 
Held-to-maturity Securities
304 
309 
Electric [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Property and plant, at original cost
20,942 1
20,098 1
Gas [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Property and plant, at original cost
1,854 1
1,751 1
Nuclear Fuel [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Construction work in progress
317 1
255 1
Other Energy [Member]
 
 
Property, Plant and Equipment [Line Items]
 
 
Construction work in progress
$ 581 1
$ 612 1
Property And Plant, Net (Accrued Capital Expenditures) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Property, Plant and Equipment [Line Items]
 
 
 
Accrued capital expenditures
$ 103 
$ 92 
$ 70 
Short-Term Debt And Liquidity (Narrative) (Details) (USD $)
12 Months Ended 12 Months Ended
Nov. 14, 2012
Illinois Credit Agreement 2012 [Member]
Dec. 31, 2012
Illinois Credit Agreement 2012 [Member]
Maximum [Member]
Dec. 31, 2012
Illinois Credit Agreement 2012 [Member]
Ameren Illinois Company [Member]
Nov. 14, 2012
Missouri Credit Agreement 2012 [Member]
Dec. 31, 2012
Missouri Credit Agreement 2012 [Member]
Maximum [Member]
Dec. 31, 2012
Missouri Credit Agreement 2012 [Member]
Union Electric Company [Member]
Dec. 31, 2012
Credit Agreements 2012 [Member]
Dec. 31, 2012
Unilateral Borrowing Agreement [Member]
Ameren Illinois Company [Member]
Dec. 31, 2012
Multiyear Credit Facility [Member]
lender
Dec. 31, 2012
Multiyear Credit Facility [Member]
Maximum [Member]
Dec. 31, 2012
Commercial Paper [Member]
Dec. 31, 2011
Commercial Paper [Member]
Dec. 31, 2012
Utilities [Member]
Dec. 31, 2012
Non State Regulated Subsidiaries [Member]
Dec. 31, 2011
Non State Regulated Subsidiaries [Member]
Line of Credit Facility [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line of credit facility, maximum borrowing capacity
$ 1,100,000,000.0 
$ 1,300,000,000.0 
$ 800,000,000 
$ 1,000,000,000 
$ 1,200,000,000.0 
$ 800,000,000 
$ 2,090,000,000.00 
$ 500,000,000 
$ 2,100,000,000.0 
 
 
 
 
 
 
Number of lenders
 
 
 
 
 
 
 
 
24 
 
 
 
 
 
 
Line of credit facility, maximum borrowing capacity, per lender
 
 
 
 
 
 
 
 
125,000,000 
 
 
 
 
 
 
Commercial paper outstanding
 
 
 
 
 
 
 
 
 
 
 
148,000,000 
 
 
 
Average daily commercial paper borrowings outstanding
 
 
 
 
 
 
 
 
 
 
49,000,000 
311,000,000 
 
 
 
Weighted average interest rate
 
 
 
 
 
 
 
 
 
 
0.92% 
0.87% 
 
 
 
Peak short-term borrowings
 
 
 
 
 
 
 
 
 
 
229,000,000 
435,000,000 
 
 
 
Peak short-term borrowings interest rate
 
 
 
 
 
 
 
 
 
 
1.25% 
1.46% 
 
 
 
Debt-to-capital ratio
 
 
 
 
 
 
 
 
0.51 
0.65 
 
 
 
 
 
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
 
 
 
 
 
 
2.0 to 1.0 
 
 
 
 
 
 
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
 
 
 
 
 
 
5.0 to 1.0 
 
 
 
 
 
 
Covenant terms, default provisions, maximum indebtedness
 
 
 
 
 
 
$ 50,000,000 
 
 
 
 
 
 
 
 
Short Term Debt, Weighted Average Interest Rate During Period
 
 
 
 
 
 
 
 
 
 
 
 
0.13% 
0.61% 
0.77% 
Letters of credit portion of aggregate commitment
 
 
 
 
 
 
 
 
25.00% 
 
 
 
 
 
 
Short-Term Debt And Liquidity (Schedule Of Maximum Aggregate Amount Available On Credit Agreements) (Details) (USD $)
Nov. 14, 2012
Illinois Credit Agreement 2012 [Member]
Dec. 31, 2012
Illinois Credit Agreement 2012 [Member]
Parent Company [Member]
Dec. 31, 2012
Illinois Credit Agreement 2012 [Member]
Ameren Illinois Company [Member]
Nov. 14, 2012
Missouri Credit Agreement 2012 [Member]
Dec. 31, 2012
Missouri Credit Agreement 2012 [Member]
Parent Company [Member]
Dec. 31, 2012
Missouri Credit Agreement 2012 [Member]
Union Electric Company [Member]
Line of Credit Facility [Line Items]
 
 
 
 
 
 
Line of credit facility, maximum borrowing capacity
$ 1,100,000,000.0 
$ 300,000,000 
$ 800,000,000 
$ 1,000,000,000 
$ 500,000,000 
$ 800,000,000 
Short-Term Debt And Liquidity (Borrowing Activity On Credit Agreements) (Details) (2010 Missouri Credit Agreement [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Line of Credit Facility [Line Items]
 
 
Average daily borrowings outstanding
$ 1 1
$ 105 
Weighted-average interest rate
4.15% 1
2.30% 
Peak credit facility borrowings
50 1
340 
Peak interest rate
4.15% 
4.30% 
Parent Company [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Average daily borrowings outstanding
 
105 
Weighted-average interest rate
 
2.30% 
Peak credit facility borrowings
 
340 
Peak interest rate
 
4.30% 
Union Electric Company [Member]
 
 
Line of Credit Facility [Line Items]
 
 
Average daily borrowings outstanding
1 1
 
Weighted-average interest rate
4.15% 1
 
Peak credit facility borrowings
$ 50 1
 
Peak interest rate
4.15% 
 
Long-Term Debt And Equity Financings (Narrative) (Details) (USD $)
12 Months Ended 12 Months Ended 1 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2011
401 (K) [Member]
Dec. 31, 2010
401 (K) [Member]
Dec. 31, 2012
DRPlus [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
Dec. 31, 2012
Ameren Missouri and Ameren Illinois [Member]
Nov. 30, 2012
Series1992 B 6.20% Due 2012 [Member]
Ameren Illinois Company [Member]
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Dec. 31, 2012
Series1992 B 6.20% Due 2012 [Member]
Ameren Illinois Company [Member]
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Dec. 31, 2011
Series1992 B 6.20% Due 2012 [Member]
Ameren Illinois Company [Member]
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Aug. 20, 2012
Senior Secured Notes, 2 Point 70, Due 2022 [Member]
Ameren Illinois Company [Member]
Secured Debt [Member]
Dec. 31, 2012
Senior Secured Notes, 2 Point 70, Due 2022 [Member]
Ameren Illinois Company [Member]
Secured Debt [Member]
Dec. 31, 2011
Senior Secured Notes, 2 Point 70, Due 2022 [Member]
Ameren Illinois Company [Member]
Secured Debt [Member]
Sep. 11, 2012
3.90% Senior secured notes due 2042 [Member]
Union Electric Company [Member]
Secured Debt [Member]
Dec. 31, 2012
3.90% Senior secured notes due 2042 [Member]
Union Electric Company [Member]
Secured Debt [Member]
Sep. 20, 2012
3.90% Senior secured notes due 2042 [Member]
Union Electric Company [Member]
Secured Debt [Member]
Dec. 31, 2011
3.90% Senior secured notes due 2042 [Member]
Union Electric Company [Member]
Secured Debt [Member]
Sep. 20, 2012
5.25% Senior secured notes due 2012 [Member]
Union Electric Company [Member]
Secured Debt [Member]
Dec. 31, 2012
5.25% Senior secured notes due 2012 [Member]
Union Electric Company [Member]
Secured Debt [Member]
Dec. 31, 2011
5.25% Senior secured notes due 2012 [Member]
Union Electric Company [Member]
Secured Debt [Member]
Aug. 27, 2012
Series A 2000 5.50% Due 2014 [Member]
Ameren Illinois Company [Member]
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Dec. 31, 2012
Series A 2000 5.50% Due 2014 [Member]
Ameren Illinois Company [Member]
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Dec. 31, 2011
Series A 2000 5.50% Due 2014 [Member]
Ameren Illinois Company [Member]
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Dec. 31, 2012
Minimum [Member]
Ameren Illinois Company [Member]
Long-Term Debt And Equity Financings [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock, authorized
100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock, par value
$ 0.01 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred stock, shares outstanding
0 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock, shares authorized
400,000,000 
400,000,000 
 
 
 
6,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock, shares issued
   
2,200,000 
3,000,000 
2,200,000 
3,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock, value of shares issued
   
$ 65,000,000 
$ 80,000,000 
$ 65,000,000 
$ 80,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument face amount
 
 
 
 
 
 
 
 
 
   1
1,000,000 
400,000,000 
400,000,000 2 3
   2 3
485,000,000 
485,000,000 4 5
485,000,000 
0 4 5
 
0 5
173,000,000 5
 
   
51,000,000 
 
Stated interest rate on debt instrument
 
 
 
 
 
 
 
 
6.20% 
6.20% 
 
2.70% 
2.70% 
 
3.90% 
3.90% 
3.90% 
 
5.25% 
5.25% 
 
5.50% 
5.50% 
 
 
Proceeds from issuance of secured debt
 
 
 
 
 
 
 
 
 
 
 
397,000,000 
 
 
478,000,000 
 
 
 
 
 
 
 
 
 
 
Repayments of long-term debt
 
 
 
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
 
 
 
173,000,000 
 
 
51,000,000 
 
 
 
Bonds interest rate assumption
 
 
 
 
 
 
 
6.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend rate on preferred shares, percentage
 
 
 
 
 
 
 
7.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Excess in indebtedness upon default of maturity
$ 25,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common stock equity to capitalization ratio
 
 
 
 
 
 
57.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
30.00% 
[2] These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028.
[5] These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042.
Long-Term Debt And Equity Financings (Schedule Of Long-Term Debt Outstanding) (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2012
Parent Company [Member]
Dec. 31, 2011
Parent Company [Member]
Dec. 31, 2012
Parent Company [Member]
8.875% Senior unsecured notes due 2014 [Member]
Dec. 31, 2011
Parent Company [Member]
8.875% Senior unsecured notes due 2014 [Member]
Dec. 31, 2012
Union Electric Company [Member]
Dec. 31, 2011
Union Electric Company [Member]
Dec. 31, 2012
Union Electric Company [Member]
City Of Bowling Green Capital Lease Peno Creek Ct [Member]
Dec. 31, 2011
Union Electric Company [Member]
City Of Bowling Green Capital Lease Peno Creek Ct [Member]
Dec. 31, 2012
Union Electric Company [Member]
Audrain County Capital Lease Audrain County Ct [Member]
Dec. 31, 2011
Union Electric Company [Member]
Audrain County Capital Lease Audrain County Ct [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
Dec. 31, 2011
Ameren Illinois Company [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.25% Senior secured notes due 2012 [Member]
Sep. 20, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.25% Senior secured notes due 2012 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.25% Senior secured notes due 2012 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
4.65% Senior secured notes due 2013 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
4.65% Senior secured notes due 2013 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.50% Senior secured notes due 2014 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.50% Senior secured notes due 2014 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
4.75% Senior secured notes due 2015 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
4.75% Senior secured notes due 2015 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.40% Senior secured notes due 2016 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.40% Senior secured notes due 2016 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
6.40% Senior secured notes due 2017 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
6.40% Senior secured notes due 2017 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
6.00% Senior secured notes due 2018 [Member]
Sep. 20, 2012
Secured Debt [Member]
Union Electric Company [Member]
6.00% Senior secured notes due 2018 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
6.00% Senior secured notes due 2018 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.10% Senior secured notes due 2018 [Member]
Sep. 20, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.10% Senior secured notes due 2018 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.10% Senior secured notes due 2018 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
6.70% Senior secured notes due 2019 [Member]
Sep. 20, 2012
Secured Debt [Member]
Union Electric Company [Member]
6.70% Senior secured notes due 2019 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
6.70% Senior secured notes due 2019 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.10% Senior secured notes due 2019 [Member]
Sep. 20, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.10% Senior secured notes due 2019 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.10% Senior secured notes due 2019 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.00% Senior secured notes due 2020 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.00% Senior secured notes due 2020 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.50% Senior secured notes due 2034 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.50% Senior secured notes due 2034 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
5.30% Senior secured notes due 2037 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
5.30% Senior secured notes due 2037 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
8.45% Senior secured notes due 2039 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
8.45% Senior secured notes due 2039 [Member]
Dec. 31, 2012
Secured Debt [Member]
Union Electric Company [Member]
3.90% Senior secured notes due 2042 [Member]
Sep. 20, 2012
Secured Debt [Member]
Union Electric Company [Member]
3.90% Senior secured notes due 2042 [Member]
Sep. 11, 2012
Secured Debt [Member]
Union Electric Company [Member]
3.90% Senior secured notes due 2042 [Member]
Dec. 31, 2011
Secured Debt [Member]
Union Electric Company [Member]
3.90% Senior secured notes due 2042 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 8.875% Due 2013 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 8.875% Due 2013 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.20% Due 2016 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.20% Due 2016 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.25% Due 2016 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.25% Due 2016 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.125% Due 2017 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.125% Due 2017 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.25% Due 2018 [Member]
Aug. 27, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.25% Due 2018 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.25% Due 2018 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 9.75% Due 2018 [Member]
Aug. 27, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 9.75% Due 2018 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 9.75% Due 2018 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes, 2 Point 70, Due 2022 [Member]
Aug. 20, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes, 2 Point 70, Due 2022 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes, 2 Point 70, Due 2022 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.125% Due 2028 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.125% Due 2028 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.70% Due 2036 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.70% Due 2036 [Member]
Dec. 31, 2012
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.70% Due 2036 [Member]
Dec. 31, 2011
Secured Debt [Member]
Ameren Illinois Company [Member]
Senior Secured Notes 6.70% Due 2036 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1992 Series due 2022 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1992 Series due 2022 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1993 5.45% Series due 2028 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1993 5.45% Series due 2028 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1998 Series A due 2033 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1998 Series A due 2033 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1998 Series B due 2033 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1998 Series B due 2033 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1998 Series C due 2033 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Union Electric Company [Member]
1998 Series C due 2033 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1992 B 6.20% Due 2012 [Member]
Nov. 30, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1992 B 6.20% Due 2012 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1992 B 6.20% Due 2012 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series A 2000 5.50% Due 2014 [Member]
Aug. 27, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series A 2000 5.50% Due 2014 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series A 2000 5.50% Due 2014 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1993 5.90% Due 2023 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1993 5.90% Due 2023 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1994A 5.70% Due 2024 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1994A 5.70% Due 2024 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series C-1 1993 5.95% Due 2026 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series C-1 1993 5.95% Due 2026 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series C-2 1993 5.70% Due 2026 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series C-2 1993 5.70% Due 2026 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series B-1 1993 Due 2028 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series B-1 1993 Due 2028 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1998A 5.40% Due 2028 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1998A 5.40% Due 2028 [Member]
Dec. 31, 2012
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1998B 5.40% Due 2028 [Member]
Dec. 31, 2011
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company [Member]
Series1998B 5.40% Due 2028 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt instrument face amount
 
 
 
 
$ 425,000,000 
$ 425,000,000 
 
 
 
 
 
 
 
 
$ 0 1
 
$ 173,000,000 1
$ 200,000,000 1
$ 200,000,000 1
$ 104,000,000 1
$ 104,000,000 1
$ 114,000,000 1
$ 114,000,000 1
$ 260,000,000 1
$ 260,000,000 1
$ 425,000,000 1
$ 425,000,000 1
$ 179,000,000 1 2
$ 179,000,000 
$ 250,000,000 1 2
$ 199,000,000 1
$ 199,000,000 
$ 200,000,000 1
$ 329,000,000 1 2
$ 329,000,000 
$ 450,000,000 1 2
$ 244,000,000 1
$ 244,000,000 
$ 300,000,000 1
$ 85,000,000 1
$ 85,000,000 1
$ 184,000,000 1
$ 184,000,000 1
$ 300,000,000 1
$ 300,000,000 1
$ 350,000,000 1 2
$ 350,000,000 1 2
$ 485,000,000 1 2
$ 485,000,000 
$ 485,000,000 
$ 0 1 2
$ 150,000,000 3 4
$ 150,000,000 3 4
$ 54,000,000 3
$ 54,000,000 3
$ 75,000,000 5
$ 75,000,000 5
$ 250,000,000 5 6
$ 250,000,000 5 6
$ 144,000,000 5 6
$ 144,000,000 
$ 337,000,000 5 6
$ 313,000,000 5 6
$ 313,000,000 
$ 400,000,000 5 6
$ 400,000,000 5 6
$ 400,000,000 
    5 6
$ 60,000,000 5
$ 60,000,000 5
$ 61,000,000 5
$ 61,000,000 5
$ 42,000,000 3
$ 42,000,000 3
$ 47,000,000 7 8
$ 47,000,000 7 8
$ 44,000,000 9
$ 44,000,000 9
$ 60,000,000 7 8
$ 60,000,000 7 8
$ 50,000,000 7 8
$ 50,000,000 7 8
$ 50,000,000 7 8
$ 50,000,000 7 8
    10
 
$ 1,000,000 
    
 
$ 51,000,000 
$ 32,000,000 10
$ 32,000,000 10
$ 36,000,000 11
$ 36,000,000 11
$ 35,000,000 12
$ 35,000,000 12
$ 8,000,000 12
$ 8,000,000 12
$ 17,000,000 12 7
$ 17,000,000 12 7
$ 19,000,000 11
$ 19,000,000 11
$ 33,000,000 11
$ 33,000,000 11
Capital lease obligations
 
 
 
 
 
 
 
 
64,000,000 
69,000,000 
240,000,000 
240,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair-market value adjustments
 
 
 
 
 
 
 
 
 
 
 
 
4,000,000 
5,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt, gross
 
 
 
 
 
 
4,013,000,000 
3,955,000,000 
 
 
 
 
1,733,000,000 
1,666,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less: Unamortized discount and premium
 
 
1,000,000 
1,000,000 
 
 
7,000,000 
5,000,000 
 
 
 
 
6,000,000 
8,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less: Maturities due within one year
(355,000,000)
(179,000,000)
 
 
 
 
(205,000,000)
(178,000,000)
 
 
 
 
(150,000,000)
(1,000,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt, Net
$ 5,802,000,000 
$ 5,853,000,000 
$ 424,000,000 
$ 424,000,000 
 
 
$ 3,801,000,000 
$ 3,772,000,000 
 
 
 
 
$ 1,577,000,000 
$ 1,657,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt interest rate
 
 
 
 
8.875% 
 
 
 
 
 
 
 
 
 
5.25% 
5.25% 
 
4.65% 
 
5.50% 
 
4.75% 
 
5.40% 
 
6.40% 
 
6.00% 
6.00% 
 
5.10% 
5.10% 
 
6.70% 
6.70% 
 
5.10% 
5.10% 
 
5.00% 
 
5.50% 
 
5.30% 
 
8.45% 
 
3.90% 
3.90% 
3.90% 
 
8.875% 
 
6.20% 
 
6.25% 
 
6.125% 
 
6.25% 
6.25% 
 
9.75% 
9.75% 
 
2.70% 
2.70% 
 
6.125% 
 
6.70% 
 
6.70% 
 
 
 
5.45% 
 
 
 
 
 
 
 
6.20% 
6.20% 
 
5.50% 
5.50% 
 
5.90% 
 
5.70% 
 
5.95% 
 
5.70% 
 
 
 
5.40% 
 
5.40% 
 
Long-term debt maturity date
 
 
 
 
2014 
 
 
 
2022 
 
2033 
 
 
 
2012 
 
 
2013 
 
2014 
 
2015 
 
2016 
 
2017 
 
2018 
 
 
2018 
 
 
2019 
 
 
2019 
 
 
2020 
 
2034 
 
2037 
 
2039 
 
2042 
 
 
 
2013 
 
2016 
 
2016 
 
2017 
 
2018 
 
 
2018 
 
 
2022 
 
 
2028 
 
2036 
 
2036 
 
2022 
 
2028 
 
2033 
 
2033 
 
2033 
 
2012 
 
 
2014 
 
 
2023 
 
2024 
 
2026 
 
2026 
 
2028 
 
2028 
 
2028 
 
Debt instrument, interest rate, maximum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
18.00% 
 
 
 
18.00% 
 
18.00% 
 
18.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Redemption price, percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
100.00% 
 
100.00% 
 
100.00% 
 
100.00% 
 
100.00% 
 
100.00% 
 
100.00% 
 
[1] These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042.
[3] These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the CILCO first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2023.
[5] These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028.
Long-Term Debt And Equity Financings (Schedule Of Average Interest Rates) (Details)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
1992 Series due 2022 [Member] |
Union Electric Company [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt instrument, interest rate during period
0.30% 
0.34% 
1998 Series A due 2033 [Member] |
Union Electric Company [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt instrument, interest rate during period
0.65% 
0.69% 
1998 Series B due 2033 [Member] |
Union Electric Company [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt instrument, interest rate during period
0.64% 
0.68% 
1998 Series C due 2033 [Member] |
Union Electric Company [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt instrument, interest rate during period
0.64% 
0.69% 
Series B-1 1993 Due 2028 [Member] |
Ameren Illinois Company [Member]
 
 
Debt Instrument [Line Items]
 
 
Debt instrument, interest rate during period
0.22% 
0.28% 
Long-Term Debt And Equity Financings (Schedule Of Maturities Of Long-Term Debt) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Debt Instrument [Line Items]
 
 
2013
$ 355 
 
2014
534 
 
2015
120 
 
2016
395 
 
2017
681 
 
Thereafter
4,082 
 
Total
6,167 
 
Parent Company [Member]
 
 
Debt Instrument [Line Items]
 
 
2013
   
 
2014
425 
 
2015
   
 
2016
   
 
2017
   
 
Thereafter
   
 
Total
425 
 
Unamortized discount and premium
1 
1 
Union Electric Company [Member]
 
 
Debt Instrument [Line Items]
 
 
2013
205 1
 
2014
109 1
 
2015
120 1
 
2016
266 1
 
2017
431 1
 
Thereafter
2,882 1
 
Total
4,013 1
 
Unamortized discount and premium
7 
5 
Ameren Illinois Company [Member]
 
 
Debt Instrument [Line Items]
 
 
2013
150 1 2
 
2014
   1 2
 
2015
   1 2
 
2016
129 1 2
 
2017
250 1 2
 
Thereafter
1,200 1 2
 
Total
1,729 1 2
 
Unamortized discount and premium
6 
8 
Fair value adjustments
$ 4 
 
Long-Term Debt And Equity Financings (Schedule Of Outstanding Preferred Stock) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Long-Term Debt And Equity Financings [Line Items]
 
 
Preferred stock, par value
$ 0.01 
 
Preferred stock, authorized
100,000,000 
 
Preferred stock, shares outstanding
0 
 
Preferred stock, issued
$ 142 1
$ 142 1
Preferred stock, voluntary liquidation
$ 106 
 
Union Electric Company [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Preferred stock, issued
80 
80 
Union Electric Company [Member] |
Par Value $100 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Preferred stock, par value
$ 100 
 
Preferred stock, authorized
25,000,000 
 
Union Electric Company [Member] |
Series $3.50 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 3.50 
 
Preferred stock, shares outstanding
130,000 
 
Preferred stock, redemption price per share
$ 110 
 
Preferred stock, issued
13 
13 
Union Electric Company [Member] |
Series $3.70 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 3.70 
 
Preferred stock, shares outstanding
40,000 
 
Preferred stock, redemption price per share
$ 105 
 
Preferred stock, issued
4 
4 
Union Electric Company [Member] |
Series $4.00 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 4.00 
 
Preferred stock, shares outstanding
150,000 
 
Preferred stock, redemption price per share
$ 106 
 
Preferred stock, issued
15 
15 
Union Electric Company [Member] |
Series $4.30 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 4.30 
 
Preferred stock, shares outstanding
40,000 
 
Preferred stock, redemption price per share
$ 105 
 
Preferred stock, issued
4 
4 
Union Electric Company [Member] |
Series $4.50 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 4.50 
 
Preferred stock, shares outstanding
213,595 
 
Preferred stock, redemption price per share
$ 110 2
 
Preferred stock, issued
21 
21 
Union Electric Company [Member] |
Series $4.56 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 4.56 
 
Preferred stock, shares outstanding
200,000 
 
Preferred stock, redemption price per share
$ 102 
 
Preferred stock, issued
20 
20 
Union Electric Company [Member] |
Series $4.75 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 4.75 
 
Preferred stock, shares outstanding
20,000 
 
Preferred stock, redemption price per share
$ 102 
 
Preferred stock, issued
2 
2 
Union Electric Company [Member] |
Series $5.50 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, per-dollar amount
$ 5.50 
 
Preferred stock, shares outstanding
14,000 
 
Preferred stock, redemption price per share
$ 110 
 
Preferred stock, issued
1 
1 
Ameren Illinois Company [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Preferred stock, issued
62 
62 
Ameren Illinois Company [Member] |
Par Value $100 [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Preferred stock, par value
$ 100 
 
Preferred stock, authorized
2,000,000 
 
Ameren Illinois Company [Member] |
Series 4.00% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.00% 
 
Preferred stock, shares outstanding
144,275 
 
Preferred stock, redemption price per share
$ 101 
 
Preferred stock, issued
14 
14 
Ameren Illinois Company [Member] |
Series 4.08% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.08% 
 
Preferred stock, shares outstanding
45,224 
 
Preferred stock, redemption price per share
$ 103 
 
Preferred stock, issued
5 
5 
Ameren Illinois Company [Member] |
Series 4.20% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.20% 
 
Preferred stock, shares outstanding
23,655 
 
Preferred stock, redemption price per share
$ 104 
 
Preferred stock, issued
2 
2 
Ameren Illinois Company [Member] |
Series 4.25% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.25% 
 
Preferred stock, shares outstanding
50,000 
 
Preferred stock, redemption price per share
$ 102 
 
Preferred stock, issued
5 
5 
Ameren Illinois Company [Member] |
Series 4.26% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.26% 
 
Preferred stock, shares outstanding
16,621 
 
Preferred stock, redemption price per share
$ 103 
 
Preferred stock, issued
2 
2 
Ameren Illinois Company [Member] |
Series 4.42% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.42% 
 
Preferred stock, shares outstanding
16,190 
 
Preferred stock, redemption price per share
$ 103 
 
Preferred stock, issued
2 
2 
Ameren Illinois Company [Member] |
Series 4.70% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.70% 
 
Preferred stock, shares outstanding
18,429 
 
Preferred stock, redemption price per share
$ 103 
 
Preferred stock, issued
2 
2 
Ameren Illinois Company [Member] |
Series 4.90% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.90% 
 
Preferred stock, shares outstanding
73,825 
 
Preferred stock, redemption price per share
$ 102 
 
Preferred stock, issued
7 
7 
Ameren Illinois Company [Member] |
Series 4.92% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
4.92% 
 
Preferred stock, shares outstanding
49,289 
 
Preferred stock, redemption price per share
$ 104 
 
Preferred stock, issued
5 
5 
Ameren Illinois Company [Member] |
Series 5.16% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
5.16% 
 
Preferred stock, shares outstanding
50,000 
 
Preferred stock, redemption price per share
$ 102 
 
Preferred stock, issued
5 
5 
Ameren Illinois Company [Member] |
Series 6.625% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
6.625% 
 
Preferred stock, shares outstanding
124,274 
 
Preferred stock, redemption price per share
$ 100 
 
Preferred stock, issued
12 
12 
Ameren Illinois Company [Member] |
Series 7.75% [Member]
 
 
Long-Term Debt And Equity Financings [Line Items]
 
 
Dividend rate on preferred shares, percentage
7.75% 
 
Preferred stock, shares outstanding
4,542 
 
Preferred stock, redemption price per share
$ 100 
 
Preferred stock, issued
$ 1 
$ 1 
Long-Term Debt And Equity Financings (Aggregate Principal Amount of Senior Notes) (Details) (USD $)
0 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended
Dec. 31, 2012
Ameren Illinois Company [Member]
2.70% Senior Notes Due 2022 [Member]
Aug. 27, 2012
Ameren Illinois Company [Member]
Secured Debt [Member]
Senior Secured Notes 9.75% Due 2018 [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
Secured Debt [Member]
Senior Secured Notes 9.75% Due 2018 [Member]
Dec. 31, 2011
Ameren Illinois Company [Member]
Secured Debt [Member]
Senior Secured Notes 9.75% Due 2018 [Member]
Aug. 27, 2012
Ameren Illinois Company [Member]
Secured Debt [Member]
Senior Secured Notes 6.25% Due 2018 [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
Secured Debt [Member]
Senior Secured Notes 6.25% Due 2018 [Member]
Dec. 31, 2011
Ameren Illinois Company [Member]
Secured Debt [Member]
Senior Secured Notes 6.25% Due 2018 [Member]
Sep. 20, 2012
Union Electric Company [Member]
Secured Debt [Member]
6.00% Senior secured notes due 2018 [Member]
Dec. 31, 2012
Union Electric Company [Member]
Secured Debt [Member]
6.00% Senior secured notes due 2018 [Member]
Dec. 31, 2011
Union Electric Company [Member]
Secured Debt [Member]
6.00% Senior secured notes due 2018 [Member]
Sep. 20, 2012
Union Electric Company [Member]
Secured Debt [Member]
6.70% Senior secured notes due 2019 [Member]
Dec. 31, 2012
Union Electric Company [Member]
Secured Debt [Member]
6.70% Senior secured notes due 2019 [Member]
Dec. 31, 2011
Union Electric Company [Member]
Secured Debt [Member]
6.70% Senior secured notes due 2019 [Member]
Sep. 20, 2012
Union Electric Company [Member]
Secured Debt [Member]
5.10% Senior secured notes due 2018 [Member]
Dec. 31, 2012
Union Electric Company [Member]
Secured Debt [Member]
5.10% Senior secured notes due 2018 [Member]
Dec. 31, 2011
Union Electric Company [Member]
Secured Debt [Member]
5.10% Senior secured notes due 2018 [Member]
Sep. 20, 2012
Union Electric Company [Member]
Secured Debt [Member]
5.10% Senior secured notes due 2019 [Member]
Dec. 31, 2012
Union Electric Company [Member]
Secured Debt [Member]
5.10% Senior secured notes due 2019 [Member]
Dec. 31, 2011
Union Electric Company [Member]
Secured Debt [Member]
5.10% Senior secured notes due 2019 [Member]
Dec. 31, 2012
Union Electric Company [Member]
Secured Debt [Member]
3.90% Senior secured notes due 2042 [Member]
Sep. 20, 2012
Union Electric Company [Member]
Secured Debt [Member]
3.90% Senior secured notes due 2042 [Member]
Sep. 11, 2012
Union Electric Company [Member]
Secured Debt [Member]
3.90% Senior secured notes due 2042 [Member]
Dec. 31, 2011
Union Electric Company [Member]
Secured Debt [Member]
3.90% Senior secured notes due 2042 [Member]
Sep. 20, 2012
Maximum [Member]
Union Electric Company [Member]
Secured Debt [Member]
5.10% Senior secured notes due 2018 [Member]
Debt Instrument [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stated interest rate on debt instrument
2.70% 
9.75% 
9.75% 
 
6.25% 
6.25% 
 
6.00% 
6.00% 
 
6.70% 
6.70% 
 
5.10% 
5.10% 
 
5.10% 
5.10% 
 
3.90% 
3.90% 
3.90% 
 
 
Principal Amount Repurchased
 
$ 87,000,000 
 
 
$ 194,000,000 
 
 
$ 71,000,000 
 
 
$ 121,000,000 
 
 
$ 1,000,000 
 
 
$ 56,000,000 
 
 
 
 
 
 
 
Premium Plus Accrued and Unpaid Interest
 
36,000,000 1
 
 
47,000,000 1
 
 
19,000,000 2
 
 
35,000,000 2
 
 
 
 
 
12,000,000 2
 
 
 
 
 
 
1,000,000 
Principal Amount Outstanding After Tender Offer
$ 400,000,000 
$ 313,000,000 
$ 313,000,000 3 4
$ 400,000,000 3 4
$ 144,000,000 
$ 144,000,000 3 4
$ 337,000,000 3 4
$ 179,000,000 
$ 179,000,000 5 6
$ 250,000,000 5 6
$ 329,000,000 
$ 329,000,000 5 6
$ 450,000,000 5 6
$ 199,000,000 
$ 199,000,000 6
$ 200,000,000 6
$ 244,000,000 
$ 244,000,000 6
$ 300,000,000 6
$ 485,000,000 5 6
$ 485,000,000 
$ 485,000,000 
$ 0 5 6
 
[3] These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028.
[6] These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042.
Long-Term Debt And Equity Financings (Schedule of Required and Actual Debt Ratios) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Union Electric Company [Member]
 
Debt Instrument [Line Items]
 
Bonds Issuable Based On Coverage Ratio
$ 4,056 1
Preferred Stock Issuable Based On Coverage Ratio
2,351 
Retired Bond Capacity
485 
Union Electric Company [Member] |
Minimum Required Ratio [Member] |
Minimum [Member]
 
Debt Instrument [Line Items]
 
Interest Coverage Ratio
2.0 2
Dividend Coverage Ratio
2.5 3
Union Electric Company [Member] |
Actual Ratio [Member]
 
Debt Instrument [Line Items]
 
Interest Coverage Ratio
4.6 
Dividend Coverage Ratio
122.8 
Ameren Illinois Company [Member]
 
Debt Instrument [Line Items]
 
Bonds Issuable Based On Coverage Ratio
3,439 1 4
Preferred Stock Issuable Based On Coverage Ratio
203 
Retired Bond Capacity
$ 645 
Ameren Illinois Company [Member] |
Minimum Required Ratio [Member] |
Minimum [Member]
 
Debt Instrument [Line Items]
 
Interest Coverage Ratio
2.0 2
Dividend Coverage Ratio
1.5 3
Ameren Illinois Company [Member] |
Actual Ratio [Member]
 
Debt Instrument [Line Items]
 
Interest Coverage Ratio
7.1 
Dividend Coverage Ratio
2.8 
Other Income And Expenses (Other Income And Expenses) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Other Nonoperating Income (Expense) [Line Items]
 
 
 
Interest and dividend income
$ 4 1
$ 3 
$ 4 
Interest income on industrial development revenue bonds
28 
28 
28 
Allowance for equity funds used during construction
36 
34 
52 
Other
2 
3 
4 
Total miscellaneous income
70 
68 
88 
Donations
24 2
8 
19 
Other
13 
15 
13 
Total miscellaneous expense
37 
23 
32 
Illinois Science and Energy Innovation Trust [Member] |
Ameren Illinois Company [Member]
 
 
 
Other Nonoperating Income (Expense) [Line Items]
 
 
 
One-time Donation
7.5 
 
 
Annual Donation
1 
 
 
Customer Assistance Programs [Member] |
Ameren Illinois Company [Member]
 
 
 
Other Nonoperating Income (Expense) [Line Items]
 
 
 
Annual Donation
$ 1 
 
 
Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Details)
Dec. 31, 2012
T
Dec. 31, 2011
T
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Coal [Member]
 
 
Derivative [Line Items]
 
 
Quantity
96,000,000 1
116,000,000 1
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Quantity
20,000,000 1
50,000,000 1
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Quantity
24,000,000 1
12,000,000 1
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Renewable energy credits [Member]
 
 
Derivative [Line Items]
 
 
Quantity
15,000,000 1 2
16,000,000 1 2
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Quantity
5,142,000 1
5,553,000 1
Other Contract [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Quantity
   3
9,000,000 3
Other Contract [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Quantity
2,000,000 3
1,000,000 3
Derivatives That Qualify for Regulatory Deferral [Member] |
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Quantity
70,000,000 4 5
53,000,000 4 5
Derivatives That Qualify for Regulatory Deferral [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Quantity
147,000,000 5
193,000,000 5
Derivatives That Qualify for Regulatory Deferral [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Quantity
23,000,000 5
21,000,000 5
Derivatives That Qualify for Regulatory Deferral [Member] |
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Quantity
446,000 5
148,000 5
Derivative Financial Instruments (Derivative Instruments Carrying Value) (Details) (Not Designated As Hedging Instrument [Member], USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Derivative [Line Items]
 
 
Derivative assets
$ 29 1
$ 134 1
Derivative liabilities
230 1
223 1
Fuel Oils [Member] |
Other current assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
8 1
17 1
Fuel Oils [Member] |
Other assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
4 1
6 1
Fuel Oils [Member] |
MTM derivative liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 1
1 1
Fuel Oils [Member] |
Other deferred credits and liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 1
   1
Natural Gas [Member] |
Other current assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
3 1
Natural Gas [Member] |
Other assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
1 1
Natural Gas [Member] |
MTM derivative liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
64 1
103 1
Natural Gas [Member] |
Other deferred credits and liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
45 1
92 1
Power [Member] |
Other current assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
14 1
30 1
Power [Member] |
Other assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
77 1
Power [Member] |
MTM derivative liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
25 1
18 1
Power [Member] |
Other deferred credits and liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
90 1
8 1
Uranium [Member] |
MTM derivative liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
1 1
   1
Uranium [Member] |
Other deferred credits and liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
$ 1 1
$ 1 1
Derivative Financial Instruments (Cumulative Amount Of Pretax Net Gains (Losses) On All Derivative Instruments In OCI) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
$ 100 
$ 133 
Current losses deferred as regulatory assets
247 
215 
Power [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
14 
 
Current losses deferred as regulatory assets
24 
 
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
4 
 
Current losses deferred as regulatory assets
1 
 
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
1 
 
Current losses deferred as regulatory assets
64 
 
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
1 
 
Regulatory Liabilities Or Assets [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(99)1
81 1
Regulatory Liabilities Or Assets [Member] |
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
4 2
19 2
Regulatory Liabilities Or Assets [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(107)3
(191)3
Regulatory Liabilities Or Assets [Member] |
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
$ (2)4
$ (1)4
Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
$ 23 
$ 156 
Affiliates [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
   
1 
Coal Producers [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
   
35 
Commodity Marketing Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
2 
85 
Electric Utilities [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
3 
4 
Financial Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
15 
27 
Municipalities/Cooperatives [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
$ 3 
$ 4 
Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 15 
$ 150 
Affiliates [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
   
1 
Coal Producers [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
   
35 
Commodity Marketing Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
1 
85 
Electric Utilities [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
1 
3 
Financial Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
10 
22 
Municipalities/Cooperatives [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 3 
$ 4 
Derivative Financial Instruments (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Derivative Instrument Detail [Abstract]
 
 
Counterparty letters of credit held as collateral
$ 1 
$ 1 
Derivative Financial Instruments (Other Derivatives) (Details) (Not Designated As Hedging Instrument [Member], Natural Gas (Generation) [Member], Operating Expenses-Fuel [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Not Designated As Hedging Instrument [Member] |
Natural Gas (Generation) [Member] |
Operating Expenses-Fuel [Member]
 
 
Derivative [Line Items]
 
 
Gain (Loss) Recognized in Income
    
$ (1)
Derivative Financial Instruments (Derivatives That Qualify For Regulatory Deferral) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Derivative [Line Items]
 
 
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets
$ (112)
$ 51 
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets
(15)
   
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets
84 
(26)
Power [Member]
 
 
Derivative [Line Items]
 
 
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets
(180)
80 
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets
$ (1)
$ (3)
Fair Value Measurements (Schedule of Valuation Process and Unobservable Inputs) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Fuel Oils [Member]
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
Derivative assets
$ 8 1
Discounted Cash Flow [Member] |
Minimum [Member] |
Fuel Oils [Member]
 
Fair Value Inputs [Abstract]
 
Escalation rate
0.21% 2
Counterparty credit risk
0.12% 3 4
Credit risk
2.00% 3 4
Discounted Cash Flow [Member] |
Minimum [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Counterparty credit risk
0.22% 3 4 5
Credit risk
2.00% 3 4 5
Average bid/ask consensus peak and off-peak pricing
22 3 5
Estimated auction price for FTRs
(281)2 5
Nodal basis
(5)3 5
Discounted Cash Flow [Member] |
Minimum [Member] |
Uranium [Member]
 
Fair Value Inputs [Abstract]
 
Average bid/ask consensus pricing
43 2
Discounted Cash Flow [Member] |
Maximum [Member] |
Fuel Oils [Member]
 
Fair Value Inputs [Abstract]
 
Escalation rate
0.60% 2
Counterparty credit risk
1.00% 3 4
Credit risk
0.00% 3 4
Discounted Cash Flow [Member] |
Maximum [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Counterparty credit risk
1.00% 3 4 5
Credit risk
5.00% 3 4 5
Average bid/ask consensus peak and off-peak pricing
47 3 5
Estimated auction price for FTRs
1,851 2 5
Nodal basis
(1)3 5
Discounted Cash Flow [Member] |
Maximum [Member] |
Uranium [Member]
 
Fair Value Inputs [Abstract]
 
Average bid/ask consensus pricing
46 2
Discounted Cash Flow [Member] |
Weighted Average [Member] |
Fuel Oils [Member]
 
Fair Value Inputs [Abstract]
 
Escalation rate
0.44% 2
Counterparty credit risk
1.00% 3 4
Credit risk
0.00% 3 4
Discounted Cash Flow [Member] |
Weighted Average [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Counterparty credit risk
1.00% 3 4 5
Credit risk
5.00% 3 4 5
Average bid/ask consensus peak and off-peak pricing
31 3 5
Estimated auction price for FTRs
178 2 5
Nodal basis
(3)3 5
Discounted Cash Flow [Member] |
Weighted Average [Member] |
Uranium [Member]
 
Fair Value Inputs [Abstract]
 
Average bid/ask consensus pricing
44 2
Option Model [Member] |
Minimum [Member] |
Fuel Oils [Member]
 
Fair Value Inputs [Abstract]
 
Volatilities
7.00% 2
Option Model [Member] |
Maximum [Member] |
Fuel Oils [Member]
 
Fair Value Inputs [Abstract]
 
Volatilities
27.00% 2
Option Model [Member] |
Weighted Average [Member] |
Fuel Oils [Member]
 
Fair Value Inputs [Abstract]
 
Volatilities
24.00% 2
Fundamental Energy Production Model [Member] |
Minimum [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Estimated future gas prices
4 2 5
Fundamental Energy Production Model [Member] |
Maximum [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Estimated future gas prices
8 2 5
Fundamental Energy Production Model [Member] |
Weighted Average [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Estimated future gas prices
6 2 5
Contract Price Allocation [Member] |
Minimum [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Estimated renewable energy credit costs
5 2 5
Contract Price Allocation [Member] |
Maximum [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Estimated renewable energy credit costs
7 2 5
Contract Price Allocation [Member] |
Weighted Average [Member] |
Power [Member]
 
Fair Value Inputs [Abstract]
 
Estimated renewable energy credit costs
6 2 5
Derivative liabilities [Member] |
Fuel Oils [Member]
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
Derivative liabilities
3 1
Derivative liabilities [Member] |
Power [Member]
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
Derivative liabilities
114 1
Derivative liabilities [Member] |
Uranium [Member]
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
Derivative liabilities
2 1
Derivative assets [Member] |
Power [Member]
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
Derivative assets
14 1
Derivative assets [Member] |
Uranium [Member]
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
Derivative assets
   1
Fair Value Measurements (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Counterparty default risk liability valuation adjustment related to derivative contracts
$ 7 
$ 4 
Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
$ 406 1
$ 358 2
Assets
435 
492 
Excluded receivables, payables, and accrued income, net
2 
(1)
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
265 1
237 2
Assets
269 
259 
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
141 1
121 2
Assets
144 
122 
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Assets
22 
111 
Fuel Oils [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
8 3
 
Cash And Cash Equivalents [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
3 2
Cash And Cash Equivalents [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
3 2
Cash And Cash Equivalents [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Cash And Cash Equivalents [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Commodity Contracts [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
29 3
134 3
Derivative liabilities
230 3
223 3
Commodity Contracts [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
4 3
22 3
Derivative liabilities
8 3
20 3
Commodity Contracts [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 3
1 3
Derivative liabilities
103 3
1 3
Commodity Contracts [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
22 3
111 3
Derivative liabilities
119 3
202 3
Commodity Contracts [Member] |
Fuel Oils [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
12 3
23 3
Derivative liabilities
4 3
1 3
Commodity Contracts [Member] |
Fuel Oils [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
4 3
20 3
Derivative liabilities
1 3
1 3
Commodity Contracts [Member] |
Fuel Oils [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   3
   3
Derivative liabilities
   3
   3
Commodity Contracts [Member] |
Fuel Oils [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
8 3
3 3
Derivative liabilities
3 3
   3
Commodity Contracts [Member] |
Natural Gas [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 3
4 3
Derivative liabilities
109 3
195 3
Commodity Contracts [Member] |
Natural Gas [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   3
2 3
Derivative liabilities
7 3
19 3
Commodity Contracts [Member] |
Natural Gas [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 3
   3
Derivative liabilities
102 3
   3
Commodity Contracts [Member] |
Natural Gas [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   3
2 3
Derivative liabilities
   3
176 3
Commodity Contracts [Member] |
Power [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
15 3
107 3
Derivative liabilities
115 3
26 3
Commodity Contracts [Member] |
Power [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   3
   3
Derivative liabilities
   3
   3
Commodity Contracts [Member] |
Power [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 3
1 3
Derivative liabilities
1 3
1 3
Commodity Contracts [Member] |
Power [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
14 3
106 3
Derivative liabilities
114 3
25 3
Commodity Contracts [Member] |
Uranium [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
2 3
1 3
Commodity Contracts [Member] |
Uranium [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
   3
   3
Commodity Contracts [Member] |
Uranium [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
   3
   3
Commodity Contracts [Member] |
Uranium [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
2 3
1 3
Equity Securities [Member] |
U.S. Large Capitalization [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
264 1
234 2
Equity Securities [Member] |
U.S. Large Capitalization [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
264 1
234 2
Equity Securities [Member] |
U.S. Large Capitalization [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Equity Securities [Member] |
U.S. Large Capitalization [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Corporate Bonds [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
47 1
44 2
Debt Securities [Member] |
Corporate Bonds [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Corporate Bonds [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
47 1
44 2
Debt Securities [Member] |
Corporate Bonds [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Municipal Bonds [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 2
Debt Securities [Member] |
Municipal Bonds [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Municipal Bonds [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 2
Debt Securities [Member] |
Municipal Bonds [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
U.S. treasury and agency securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
81 1
65 2
Debt Securities [Member] |
U.S. treasury and agency securities [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
U.S. treasury and agency securities [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
81 1
65 2
Debt Securities [Member] |
U.S. treasury and agency securities [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Asset-Backed Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
11 1
10 2
Debt Securities [Member] |
Asset-Backed Securities [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Asset-Backed Securities [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
11 1
10 2
Debt Securities [Member] |
Asset-Backed Securities [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Other debt securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 2
Debt Securities [Member] |
Other debt securities [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Debt Securities [Member] |
Other debt securities [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 2
Debt Securities [Member] |
Other debt securities [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
   1
   2
Fair Value Measurements (Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level 3 In The Fair Value Hierarchy) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Fuel Oils [Member]
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
Beginning balance
$ 3 
$ 30 
Included in regulatory assets/liabilities
(1)
19 
Total realized and unrealized gains (losses)
(1)
19 
Purchases
7 
4 
Sales
(3)
(1)
Settlements
(2)
30 
Transfers into Level 3
1 
 
Transfers out of Level 3
   
(19)
Ending balance
5 
3 
Change in unrealized gains (losses) related to assets/liabilities still held
(1)
(11)
Natural Gas [Member]
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
Beginning balance
(174)
(148)
Included in regulatory assets/liabilities
(27)
(115)
Total realized and unrealized gains (losses)
(27)
(115)
Purchases
   
1 
Sales
 
(1)
Settlements
16 
89 
Transfers out of Level 3
185 
 
Ending balance
0 
(174)
Change in unrealized gains (losses) related to assets/liabilities still held
0 
(78)
Power [Member]
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
Beginning balance
81 
19 
Included in regulatory assets/liabilities
(175)
55 
Total realized and unrealized gains (losses)
(175)
55 
Purchases
21 
30 
Sales
(1)
(1)
Settlements
(22)
22 
Transfers into Level 3
 
(1)
Transfers out of Level 3
(4)
1 
Ending balance
(100)
81 
Change in unrealized gains (losses) related to assets/liabilities still held
(175)1
(25)
Derivative, term of contract
20 years 
 
Uranium [Member]
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
Beginning balance
(1)
2 
Included in regulatory assets/liabilities
(2)
(3)
Total realized and unrealized gains (losses)
(2)
(3)
Purchases
 
(1)
Settlements
1 
1 
Ending balance
(2)
(1)
Change in unrealized gains (losses) related to assets/liabilities still held
$ (1)
$ 0 
Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Transfer into of Level 3/Transfers out of Level 2
   
 
Net fair value of Level 3 transfers
182 
(19)
Fuel Oils [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Transfers into Level 3/Transfers out of Level 1
1 
   
Transfers out of Level 3/Transfers into Level1
   
(19)
Natural Gas [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Transfers out of Level 3/Transfers into Level 2
185 
   
Power [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Transfer into of Level 3/Transfers out of Level 2
 
(1)
Transfers out of Level 3/Transfers into Level 2
$ (4)
$ 1 
Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Carrying Amount [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term Debt and Capital Lease Obligations
$ 6,157 1
$ 6,032 1
Preferred stock
142 1
142 1
Fair Value [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt and capital lease obligations (including current portion)
7,110 1
6,961 1
Preferred stock
$ 123 1
$ 92 1
Nuclear Decommissioning Trust Fund Investments (Fair Values Of Investments In Debt And Equity Securities In Nuclear Decommissioning Trust Fund) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
 
Cost
$ 281 
$ 261 
Gross unrealized gains
138 
108 
Gross unrealized loss
11 
12 
Fair value
408 
357 
Debt Securities [Member]
 
 
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
 
Cost
133 
114 
Gross unrealized gains
8 
7 
Fair value
141 
121 
Equity Securities [Member]
 
 
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
 
Cost
145 
145 
Gross unrealized gains
130 
101 
Gross unrealized loss
11 
12 
Fair value
264 
234 
Cash [Member]
 
 
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
 
Cost
1 
3 
Fair value
1 
3 
Other Debt And Equity Securities [Member]
 
 
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
 
Cost
2 1
(1)1
Fair value
$ 2 1
$ (1)1
Nuclear Decommissioning Trust Fund Investments (Costs And Fair Values Of Investments In Debt Securities In Nuclear Decommissioning Trust Fund According To Contractual Maturities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Investments, Debt and Equity Securities [Abstract]
 
Cost, Less than 5 years
$ 78 
Cost, 5 years to 10 years
32 
Cost, Due after 10 years
23 
Cost, Total
133 
Fair Value, Less than 5 years
79 
Fair Value, 5 years to 10 years
35 
Fair Value, Due after 10 years
27 
Fair Value, Total
$ 141 
Nuclear Decommissioning Trust Fund Investments (Fair Value And The Gross Unrealized Losses Of The Available-For-Sale Securities Held In Nuclear Decommissioning Trust Fund) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
Less than 12 months, fair value
$ 24 
Less than 12 months, gross unrealized losses
1 
12 months or greater, fair value
14 
12 months or greater, gross unrealized losses
10 
Total, fair value
38 
Total, gross unrealized losses
11 
Debt Securities [Member]
 
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
Less than 12 months, fair value
17 
Total, fair value
17 
Equity Securities [Member]
 
Nuclear Decommissioning Trust Fund Investments [Line Items]
 
Less than 12 months, fair value
7 
Less than 12 months, gross unrealized losses
1 
12 months or greater, fair value
14 
12 months or greater, gross unrealized losses
10 
Total, fair value
21 
Total, gross unrealized losses
$ 11 
Callaway Energy Center (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
mill
Dec. 31, 2011
Dec. 31, 2010
Mar. 30, 2013
Loss Contingencies [Line Items]
 
 
 
 
Nwf Fee Number Of Mills
1 
 
 
 
Settlement payment
 
$ 11 
 
$ 5 
Annual decommissioning costs included in costs of service
7 
7 
7 
 
MoPSC requirement to file updated cost study and funding analysis for decommissioning Callaway energy center
3 years 
 
 
 
Reduction To Depreciation And Amortization [Member]
 
 
 
 
Loss Contingencies [Line Items]
 
 
 
 
Settlement payment
 
2 
 
 
Reduction To Other Operations And Maintenance [Member]
 
 
 
 
Loss Contingencies [Line Items]
 
 
 
 
Settlement payment
 
2 
 
 
Reduction In Property And Plant [Member]
 
 
 
 
Loss Contingencies [Line Items]
 
 
 
 
Settlement payment
$ 1 
$ 7 
 
 
Nuclear Plant [Member]
 
 
 
 
Loss Contingencies [Line Items]
 
 
 
 
Useful life
40 years 
 
 
 
Retirement Benefits (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
bond
Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
 
 
Other non-current assets
$ 667 
$ 760 
Number of high-quality corporate bonds
600 
 
Defined benefit plan, estimated future employer contributions during the next five years
525 
 
Actual return in excess of (or less than) expected return, percentage
25.00% 
 
Expected return on plan assets, period
4 years 
 
Amortization basis, straight line, in years
10 years 
 
Number Of Employees Who Moved To A Cash Balance Formula [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Number of employees
430 
 
Pension Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Assumptions used calculating net periodic benefit cost, expected long-term return on assets in 2013
7.50% 
 
Postretirement Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Assumptions used calculating net periodic benefit cost, expected long-term return on assets in 2013
7.25% 
 
Minimum [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Defined benefit plan, estimated future employer contributions during the next five years
50 
 
Maximum [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Defined benefit plan, estimated future employer contributions during the next five years
150 
 
Private equity [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Number of limited partnerships in private equity funds
10 
 
Minimum invested capital within limited partnership investments
0.1 
 
Maximum invested capital within limited partnership investments
5 
 
Illinois Power Holdings, LLC [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Transaction Agreement, Pension and Other Postretirement Obligations Assumed by Counterparty
40 
 
Transaction Agreement, Defined Benefit Plan Assets Assumed by Counterparty
$ 15 
 
Retirement Benefits (Funded Status Of Benefit Plans And Amounts Included In Regulatory Assets And OCI) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Amounts recognized in the consolidated balance sheet consist of:
 
 
 
Noncurrent liability
$ 1,138 
$ 1,253 
 
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Accumulated benefit obligation at end of year
3,829 1
3,553 1
 
Change in benefit obligation:
 
 
 
Net benefit obligation at beginning of year
3,764 1
3,366 1
 
Service cost
81 1
73 1
65 
Interest cost
166 1
175 1
181 
Plan amendments
0 1 2
(16)1 2
 
Participant contributions
0 1
0 1
 
Actuarial (gain) loss
240 1
335 1
 
Benefits paid
(200)1
(169)1
 
Net benefit obligation at end of year
4,051 1
3,764 1
3,366 1
Change in plan assets:
 
 
 
Fair value of plan assets at beginning of year
2,814 1
2,664 1
 
Actual return on plan assets
385 1
223 1
 
Employer contributions
128 1
96 1
81 
Participant contributions
0 1
0 1
 
Benefits paid
(200)1
(169)1
 
Fair value of plan assets at end of year
3,127 1
2,814 1
2,664 1
Funded status - deficiency
924 1
950 1
 
Accrued benefit cost at December 31
924 1
950 1
 
Amounts recognized in the consolidated balance sheet consist of:
 
 
 
Current liability
3 1
3 1
 
Noncurrent liability
921 1
947 1
 
Net liability recognized
924 1
950 1
 
Amounts recognized in regulatory assets consist of:
 
 
 
Net actuarial loss
699 1
734 1
 
Prior service cost (credit)
(6)1
(7)1
 
Transition obligation
0 1
0 1
 
Amounts (pretax) recognized in accumulated OCI consist of:
 
 
 
Net actuarial loss
65 1
54 1
 
Prior service cost (credit)
(14)1
(16)1
 
Total
744 1
765 1
 
Postretirement Benefits [Member]
 
 
 
Change in benefit obligation:
 
 
 
Net benefit obligation at beginning of year
1,145 1
1,036 1
 
Service cost
22 1
20 1
18 
Interest cost
47 1
54 1
58 
Plan amendments
0 1
0 1
 
Participant contributions
16 1
18 1
 
Actuarial (gain) loss
(10)1
71 1
 
Benefits paid
(69)1
(63)1
 
Early retiree reinsurance program receipt
2 1
3 1
 
Federal subsidy on benefits paid
4 1
6 1
 
Net benefit obligation at end of year
1,157 1
1,145 1
1,036 1
Change in plan assets:
 
 
 
Fair value of plan assets at beginning of year
836 1
735 1
 
Actual return on plan assets
104 1
8 1
 
Employer contributions
45 1
129 1
36 
Federal subsidy on benefits paid
4 1
6 1
 
Early retiree reinsurance program receipt
2 1
3 1
 
Participant contributions
16 1
18 1
 
Benefits paid
(69)1
(63)1
 
Fair value of plan assets at end of year
938 1
836 1
735 1
Funded status - deficiency
219 1
309 1
 
Accrued benefit cost at December 31
219 1
309 1
 
Amounts recognized in the consolidated balance sheet consist of:
 
 
 
Current liability
2 1
3 1
 
Noncurrent liability
217 1
306 1
 
Net liability recognized
219 1
309 1
 
Amounts recognized in regulatory assets consist of:
 
 
 
Net actuarial loss
103 1
177 1
 
Prior service cost (credit)
(24)1
(28)1
 
Transition obligation
0 1
2 1
 
Amounts (pretax) recognized in accumulated OCI consist of:
 
 
 
Net actuarial loss
5 1
5 1
 
Prior service cost (credit)
(6)1
(7)1
 
Total
$ 78 1
$ 149 1
 
Retirement Benefits (Assumptions Used To Determine Benefit Obligations) (Details)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Pension Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Discount rate at measurement date
4.00% 
4.50% 
Increase in future compensation
3.50% 
3.50% 
Medical cost trend rate (initial)
0.00% 
0.00% 
Medical cost trend rate (ultimate)
0.00% 
0.00% 
Years to ultimate rate
0 years 
0 years 
Postretirement Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Discount rate at measurement date
4.00% 
4.50% 
Increase in future compensation
3.50% 
3.50% 
Medical cost trend rate (initial)
5.00% 
5.50% 
Medical cost trend rate (ultimate)
5.00% 
5.00% 
Years to ultimate rate
0 years 
1 year 
Retirement Benefits (Cash Contributions Made To Benefit Plans) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Cash contributions to benefit plans
$ 128 1
$ 96 1
$ 81 
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Cash contributions to benefit plans
$ 45 1
$ 129 1
$ 36 
Retirement Benefits (Target Allocation Of The Plans' Asset Categories) (Details)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Pension Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Percentage of Plan Assets
100.00% 
100.00% 
Pension Benefits [Member] |
Cash and cash equivalents [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
0.00% 
 
Maximum Target Allocation
5.00% 
 
Percentage of Plan Assets
2.00% 
2.00% 
Pension Benefits [Member] |
Total equity [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
50.00% 
 
Maximum Target Allocation
60.00% 
 
Percentage of Plan Assets
54.00% 
51.00% 
Pension Benefits [Member] |
U.S. large capitalization [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
29.00% 
 
Maximum Target Allocation
39.00% 
 
Percentage of Plan Assets
34.00% 
33.00% 
Pension Benefits [Member] |
U.S. small and mid-capitalization [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
2.00% 
 
Maximum Target Allocation
12.00% 
 
Percentage of Plan Assets
7.00% 
7.00% 
Pension Benefits [Member] |
International and emerging markets [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
9.00% 
 
Maximum Target Allocation
19.00% 
 
Percentage of Plan Assets
13.00% 
11.00% 
Pension Benefits [Member] |
Debt securities [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
35.00% 
 
Maximum Target Allocation
45.00% 
 
Percentage of Plan Assets
39.00% 
42.00% 
Pension Benefits [Member] |
Real estate [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
0.00% 
 
Maximum Target Allocation
9.00% 
 
Percentage of Plan Assets
4.00% 
4.00% 
Pension Benefits [Member] |
Private equity [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
0.00% 
 
Maximum Target Allocation
4.00% 
 
Percentage of Plan Assets
1.00% 
1.00% 
Postretirement Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Percentage of Plan Assets
100.00% 
100.00% 
Postretirement Benefits [Member] |
Cash and cash equivalents [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
0.00% 
 
Maximum Target Allocation
10.00% 
 
Percentage of Plan Assets
4.00% 
4.00% 
Postretirement Benefits [Member] |
Total equity [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
55.00% 
 
Maximum Target Allocation
65.00% 
 
Percentage of Plan Assets
62.00% 
59.00% 
Postretirement Benefits [Member] |
U.S. large capitalization [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
33.00% 
 
Maximum Target Allocation
43.00% 
 
Percentage of Plan Assets
40.00% 
38.00% 
Postretirement Benefits [Member] |
U.S. small and mid-capitalization [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
3.00% 
 
Maximum Target Allocation
13.00% 
 
Percentage of Plan Assets
8.00% 
8.00% 
Postretirement Benefits [Member] |
International [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
10.00% 
 
Maximum Target Allocation
20.00% 
 
Percentage of Plan Assets
14.00% 
13.00% 
Postretirement Benefits [Member] |
Debt securities [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Minimum Target Allocation
30.00% 
 
Maximum Target Allocation
40.00% 
 
Percentage of Plan Assets
34.00% 
37.00% 
Retirement Benefits (Fair Value Of Plan Assets Utilizing Fair Value Hierarchy) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Real estate [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Purchases, Sales, and Settlements
$ 3 
$ 0 
 
Fair value of plan assets
118 
108 
98 
Private equity [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined Benefit Plan, Purchases, Sales, and Settlements
(5)
(6)
 
Fair value of plan assets
19 
23 
28 
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
3,127 1
2,814 1
2,664 1
Pension Benefits [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
452 
389 
 
Pension Benefits [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
2,611 
2,362 
 
Pension Benefits [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
137 
131 
 
Pension Benefits [Member] |
Cash and cash equivalents [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
29 
30 
 
Pension Benefits [Member] |
Cash and cash equivalents [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
1 
 
 
Pension Benefits [Member] |
Cash and cash equivalents [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
28 
30 
 
Pension Benefits [Member] |
U.S. large capitalization [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
1,090 
973 
 
Pension Benefits [Member] |
U.S. large capitalization [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
83 
72 
 
Pension Benefits [Member] |
U.S. large capitalization [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
1,007 
901 
 
Pension Benefits [Member] |
U.S. small and mid-capitalization [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
235 
202 
 
Pension Benefits [Member] |
U.S. small and mid-capitalization [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
235 
202 
 
Pension Benefits [Member] |
U.S. small and mid-capitalization [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
0 
 
 
Pension Benefits [Member] |
International and emerging markets [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
435 
323 
 
Pension Benefits [Member] |
International and emerging markets [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
134 
115 
 
Pension Benefits [Member] |
International and emerging markets [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
301 
208 
 
Pension Benefits [Member] |
Corporate bonds [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
832 
794 
 
Pension Benefits [Member] |
Corporate bonds [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
832 
794 
 
Pension Benefits [Member] |
Municipal bonds [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
176 
176 
 
Pension Benefits [Member] |
Municipal bonds [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
176 
176 
 
Pension Benefits [Member] |
U.S. treasury and agency securities [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
250 
230 
 
Pension Benefits [Member] |
U.S. treasury and agency securities [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
250 
230 
 
Pension Benefits [Member] |
Asset-backed securities [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
18 
 
 
Pension Benefits [Member] |
Other [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
17 
23 
 
Pension Benefits [Member] |
Other [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
17 
23 
 
Pension Benefits [Member] |
Real estate [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
118 
108 
 
Pension Benefits [Member] |
Real estate [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
118 
108 
 
Pension Benefits [Member] |
Private equity [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
19 
23 
 
Pension Benefits [Member] |
Private equity [Member] |
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
19 
23 
 
Pension Benefits [Member] |
Derivative assets [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
0 
1 
 
Pension Benefits [Member] |
Derivative assets [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
0 
1 
 
Pension Benefits [Member] |
Derivative liabilities [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
(1)
(1)
 
Pension Benefits [Member] |
Derivative liabilities [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
(1)
(1)
 
Pension Benefits [Member] |
Medical benefit assets [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
(102)2
(91)2
 
Pension Benefits [Member] |
Net receivables [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
29 3
23 3
 
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
938 1
836 1
735 1
Postretirement Benefits [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
439 
302 
 
Postretirement Benefits [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
443 
476 
 
Postretirement Benefits [Member] |
Cash and cash equivalents [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
83 
66 
 
Postretirement Benefits [Member] |
Cash and cash equivalents [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
83 
1 
 
Postretirement Benefits [Member] |
Cash and cash equivalents [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
0 
65 
 
Postretirement Benefits [Member] |
U.S. large capitalization [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
333 
284 
 
Postretirement Benefits [Member] |
U.S. large capitalization [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
245 
206 
 
Postretirement Benefits [Member] |
U.S. large capitalization [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
88 
78 
 
Postretirement Benefits [Member] |
U.S. small and mid-capitalization [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
66 
57 
 
Postretirement Benefits [Member] |
U.S. small and mid-capitalization [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
66 
57 
 
Postretirement Benefits [Member] |
International [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
114 
94 
 
Postretirement Benefits [Member] |
International [Member] |
Quoted Prices In Active Markets For Identical Assets Or Liabilities (Level 1) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
45 
38 
 
Postretirement Benefits [Member] |
International [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
69 
56 
 
Postretirement Benefits [Member] |
Corporate bonds [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
88 
71 
 
Postretirement Benefits [Member] |
Corporate bonds [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
88 
71 
 
Postretirement Benefits [Member] |
Municipal bonds [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
91 
80 
 
Postretirement Benefits [Member] |
Municipal bonds [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
91 
80 
 
Postretirement Benefits [Member] |
U.S. treasury and agency securities [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
67 
69 
 
Postretirement Benefits [Member] |
U.S. treasury and agency securities [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
67 
69 
 
Postretirement Benefits [Member] |
Asset-backed securities [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
18 
23 
 
Postretirement Benefits [Member] |
Asset-backed securities [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
 
23 
 
Postretirement Benefits [Member] |
Other [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
22 
34 
 
Postretirement Benefits [Member] |
Other [Member] |
Significant Other Observable Inputs (Level 2) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
22 
34 
 
Postretirement Benefits [Member] |
Medical benefit assets [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
102 2
91 2
 
Postretirement Benefits [Member] |
Net payables [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
(46)4
(33)4
 
Includes Medical Benefit Component Under Section 401(h) And Excludes Receivables Related To Pending Security Sales [Member] |
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
3,200 
2,882 
 
Excludes Medical Benefit Component Under Section 401(h) And Includes Receivables Related To Pending Security Sales [Member] |
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
3,127 
2,814 
 
Excludes Medical Benefit Component Under Section 401(h) And Excludes Payables Related To Pending Security Sales [Member] |
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
882 
778 
 
Includes Medical Benefit Component Under Section401 H And Excludes Payables Related To Pending Security Sales [Member] |
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
$ 938 
$ 836 
 
Retirement Benefits (Changes In The Fair Value Of Plan Assets Classified As Level 3) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Real estate [Member]
 
 
Change in plan assets:
 
 
Fair value of plan assets at beginning of year
$ 108 
$ 98 
Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date
7 
10 
Purchases, Sales and Settlements, net
3 
0 
Fair value of plan assets at end of year
118 
108 
Private equity [Member]
 
 
Change in plan assets:
 
 
Fair value of plan assets at beginning of year
23 
28 
Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date
(7)
(10)
Actual Return on Plan Assets Related to Assets Sold During the Period
8 
11 
Purchases, Sales and Settlements, net
(5)
(6)
Fair value of plan assets at end of year
$ 19 
$ 23 
Retirement Benefits (Components Of Net Periodic Benefit Cost) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Service cost
$ 81 1
$ 73 1
$ 65 
Interest cost
166 1
175 1
181 
Expected return on plan assets
(208)
(211)
(208)
Transition obligation
0 
0 
0 
Prior service cost
(3)
(1)
6 
Actuarial loss
75 
41 
18 
Net periodic benefit cost
111 
77 
62 
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Service cost
22 1
20 1
18 
Interest cost
47 1
54 1
58 
Expected return on plan assets
(56)
(50)
(51)
Transition obligation
2 
2 
2 
Prior service cost
(6)
(6)
(6)
Actuarial loss
5 
3 
0 
Net periodic benefit cost
$ 14 
$ 23 
$ 21 
Retirement Benefits (Summary Of Estimated Amortizable Amounts From Regulatory Assets and Accumulated OCI Into Net Periodic Benefit Cost) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Pension Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Prior service cost (credit)
$ (1)
Net actuarial loss
97 
Prior service cost (credit)
(2)
Net actuarial loss
5 
Net periodic benefit cost
99 
Postretirement Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Prior service cost (credit)
(4)
Net actuarial loss
19 
Prior service cost (credit)
(1)
Net actuarial loss
0 
Net periodic benefit cost
$ 14 
Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Net periodic benefit cost
$ 111 
$ 77 
$ 62 
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Net periodic benefit cost
$ 14 
$ 23 
$ 21 
Retirement Benefits (Schedule Of Expected Payments From Qualified Trust And Company Funds) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Pension Benefits [Member] |
Paid From Qualified Trust [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2013
$ 229 
2014
236 
2015
239 
2016
245 
2017
248 
2018 - 2022
1,279 
Pension Benefits [Member] |
Paid From Company Funds [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2013
3 
2014
3 
2015
3 
2016
3 
2017
3 
2018 - 2022
13 
Postretirement Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2013, Federal Subsidy
3 
2014, Federal Subsidy
3 
2015, Federal Subsidy
4 
2016, Federal Subsidy
4 
2017, Federal Subsidy
4 
2018 - 2022, Federal Subsidy
19 
Postretirement Benefits [Member] |
Paid From Qualified Trust [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2013
58 
2014
60 
2015
62 
2016
65 
2017
68 
2018 - 2022
384 
Postretirement Benefits [Member] |
Paid From Company Funds [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
2013
2 
2014
2 
2015
2 
2016
2 
2017
2 
2018 - 2022
$ 11 
Retirement Benefits (Assumptions Used To Determine Net Periodic Benefit Cost) (Details)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Discount rate at measurement date
4.50% 
5.25% 
5.75% 
Expected return on plan assets
7.75% 
8.00% 
8.00% 
Increase in future compensation
3.50% 
3.50% 
3.50% 
Medical cost trend rate (initial)
0.00% 
0.00% 
0.00% 
Medical cost trend rate (ultimate)
0.00% 
0.00% 
0.00% 
Years to ultimate rate
0 years 
0 years 
0 years 
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Discount rate at measurement date
4.50% 
5.25% 
5.75% 
Expected return on plan assets
7.50% 
7.75% 
8.00% 
Increase in future compensation
3.50% 
3.50% 
3.50% 
Medical cost trend rate (initial)
5.50% 
6.00% 
6.50% 
Medical cost trend rate (ultimate)
5.00% 
5.00% 
5.00% 
Years to ultimate rate
1 year 
2 years 
3 years 
Retirement Benefits (Schedule Of Potential Changes In Key Assumptions) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Pension Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Service Cost and Interest Cost, .25% decrease in discount rate
$ (2)
Benefit Obligation, .25% decrease in discount rate
121 
Service Cost and Interest Cost, .25% increase in salary rate
2 
Benefit Obligation, .25% increase in salary rate
13 
Postretirement Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Benefit Obligation, .25% decrease in discount rate
34 
Service Cost and Interest Cost, 1.00% increase in annual medical trend
0 
Benefit Obligation, 1.00% increase in annual medical trend
36 
Service Cost and Interest Cost, 1.00% decrease in annual medical trend
(1)
Benefit Obligation, 1.00% decrease in annual medical trend
$ (34)
Retirement Benefits (Schedule Of Matching Contributions) (Details) (401 (K) [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
401 (K) [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Employer contributions
$ 28 
$ 28 
$ 27 
Stock-Based Compensation (Narrative) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Jan. 31, 2012
Performance Share Units [Member]
Jan. 31, 2011
Performance Share Units [Member]
Dec. 31, 2012
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
Maximum shares available for grants
4,000,000 
 
 
 
 
 
Share-based compensation expense
$ 22 
$ 13 
$ 11 
 
 
 
Employee service share-based compensation, tax benefit from compensation expense
8 
5 
4 
 
 
 
Amounts paid to settle share units
11 
4 
2 
 
 
 
Compensation cost not yet recognized
$ 21 
 
 
 
 
 
Expected weighted average recognition period for share-based compensation expense, in months
20 months 
 
 
 
 
 
Performance period
 
 
 
 
 
3 years 
Percentage of shares issued per share unit, minimum
 
 
 
 
 
0.00% 
Percentage of shares issued per share unit, maximum
 
 
 
 
 
200.00% 
Fair value of each share unit, per share
 
 
 
$ 35.68 
$ 31.41 
$ 35.68 1
Closing common share price
 
 
 
$ 33.13 
$ 28.19 
 
Three-year risk-free rate
 
 
 
0.41% 
1.08% 
 
Volatility rate, minimum
 
 
 
17.00% 
22.00% 
 
Volatility rate, maximum
 
 
 
31.00% 
36.00% 
 
Stock-Based Compensation (Summary Of Nonvested Shares) (Details) (Performance Share Units [Member], USD $)
1 Months Ended 12 Months Ended
Jan. 31, 2012
Jan. 31, 2011
Dec. 31, 2012
Performance Share Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
 
 
 
Share Units, Granted
 
 
717,151 1
Share Units, Unearned or forfeited
 
 
(477,928)2
Share Units, Earned and vested
 
 
(203,567)3
Share Units, Nonvested at end of year
1,156,831 
 
1,192,487 
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
 
 
 
Weighted-averageFair Value per Unit, granted
$ 35.68 
$ 31.41 
$ 35.68 1
Weighted-average Fair Value per Unit, Unearned or forfeited
 
 
$ 32.04 2
Weighted-average Fair Value per Unit, Earned and vested
 
 
$ 34.01 3
Weighted-average Fair Value per Unit, Nonvested at end of year
$ 31.70 
 
$ 33.56 
Income Taxes (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Jun. 30, 2011
Dec. 31, 2011
Illinois Corporate Income Tax [Member]
Jan. 31, 2011
Minimum [Member]
Illinois Corporate Income Tax [Member]
Jan. 31, 2011
Maximum [Member]
Illinois Corporate Income Tax [Member]
Dec. 31, 2015
Income Tax Rate in 2015 [Member]
Illinois Corporate Income Tax [Member]
Dec. 31, 2025
Income Tax Rate in 2025 [Member]
Illinois Corporate Income Tax [Member]
Income Taxes [Line Items]
 
 
 
 
 
 
 
 
 
State corporate income tax rate
5.00% 
4.00% 
5.00% 
 
 
7.30% 
9.50% 
7.75% 
7.30% 
Increase in current state and local tax expense benefit
 
 
 
 
$ 6 
 
 
 
 
Decrease in deferred state and local income tax expense benefit
 
 
 
 
2 
 
 
 
 
Reduction of uncertain tax positions
 
 
 
39 
 
 
 
 
 
Estimated unrecognized tax benefits, decreases resulting from settlements with taxing authorities
$ 143 
 
 
 
 
 
 
 
 
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Taxes [Line Items]
 
 
 
Statutory federal income tax rate:
35.00% 
35.00% 
35.00% 
Depreciation differences
(1.00%)
(1.00%)
(3.00%)
Amortization of investment tax credit
(1.00%)
(1.00%)
(1.00%)
State tax
5.00% 
4.00% 
5.00% 
Reserve for uncertain tax positions
   
1.00% 
(1.00%)
Tax credits
   
(1.00%)
(1.00%)
Change in federal tax law
   1
   1
2.00% 1
Permanent items
(1.00%)2
   2
   2
Effective income tax rate
37.00% 
37.00% 
36.00% 
Income Taxes (Schedule Of Components Of Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Taxes [Line Items]
 
 
 
Current Federal taxes
$ 40 
$ (6)
$ 3 
Current State taxes
9 
(2)
(1)
Deferred Federal taxes
205 
206 
247 
Deferred State taxes
61 
53 
32 
Deferred investment tax credits, amortization
(6)
(6)
(7)
Total income tax expense
$ 309 
$ 245 
$ 274 
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Income Taxes [Line Items]
 
 
Plant related
$ 3,512 
$ 3,162 
Deferred intercompany tax gain/basis step-up
39 
54 
Regulatory assets, net
73 
73 
Deferred employee benefit costs
(323)
(320)
Purchase accounting
(27)
(28)
ARO
(17)
(12)
Other
(251)1
(217)1
Total net accumulated deferred income tax liabilities
3,006 
2,712 
Current assets
$ 170 
$ 98 
Income Taxes (Schedule Of Net Operating Loss Carryforwards And Tax Credit Carryforwards) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
 
Net operating loss carryforwards
$ 200 
Tax credit carryforwards
109 
Change in valuation allowance
1 
Federal [Member]
 
Operating Loss Carryforwards [Line Items]
 
Net operating loss carryforwards
173 1
Tax credit carryforwards
86 2
Net operating loss carryforward, expiration period start
2028 
Tax credit carryforward, expiration period start
Jan. 01, 2029 
State [Member]
 
Operating Loss Carryforwards [Line Items]
 
Net operating loss carryforwards
27 3
Tax credit carryforwards
25 4
Tax Credit Carryforward, Valuation Allowance
$ (2)5
Net operating loss carryforward, expiration period start
2017 
Tax credit carryforward, expiration period start
Jan. 01, 2013 
Income Taxes (Reconciliation Of The Change In The Liability For Interest On Unrecognized Tax Benefits) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Income Tax Contingency [Line Items]
 
 
 
Liability for interest, beginning of year
$ 5 
$ 17 
$ 8 
Interest charges (income)
1 
(11)
9 
Interest payment
   
(1)
   
Liability for interest, end of year
$ 6 
$ 5 
$ 17 
Related Party Transactions (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Related Party Transaction [Line Items]
 
 
 
Total Operating Revenues
$ 17 
$ 12 
$ 11 
Ameren Missouri and Genco Gas Transportation Agreement [Member]
 
 
 
Related Party Transaction [Line Items]
 
 
 
Total Operating Revenues
1 
1 
1 
Ameren Illinois Transmission Services Agreement with Marketing Company [Member]
 
 
 
Related Party Transaction [Line Items]
 
 
 
Total Operating Revenues
16 
11 
10 
Ameren Illinois Power Supply Agreements with Marketing Company [Member]
 
 
 
Related Party Transaction [Line Items]
 
 
 
Operating Expenses
311 
232 
233 
Ameren Illinois gas purchases from Genco [Member]
 
 
 
Related Party Transaction [Line Items]
 
 
 
Operating Expenses
    
    
$ 1 
Related Party Transactions (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 12 Months Ended 0 Months Ended 3 Months Ended 0 Months Ended 1 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2012
Ameren Energy Resources Generating Company [Member]
Dec. 31, 2012
Ameren Energy Marketing Company [Member]
Dec. 31, 2012
Midwest Independent Transmission System Operator, Inc [Member]
May 28, 2012
Ameren Energy Generating Company [Member]
Dec. 31, 2012
Ameren Energy Generating Company [Member]
Ameren Transmission Company of Illinois [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
Mar. 14, 2013
Elgin, Gibson City and Grand Tower Energy Centers [Member]
Ameren Energy Generating Company [Member]
Sep. 30, 2013
Elgin, Gibson City and Grand Tower Energy Centers [Member]
Ameren Energy Generating Company [Member]
Mar. 14, 2013
New Ameren Energy Resources Company, LLC [Member]
Apr. 30, 2010
Period Two [Member]
Ameren Energy Marketing Company [Member]
Apr. 30, 2009
Period Two [Member]
Ameren Energy Marketing Company [Member]
May 31, 2010
Period Two [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
May 31, 2009
Period Two [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
Apr. 30, 2010
Period Three [Member]
Ameren Energy Marketing Company [Member]
Apr. 30, 2009
Period Three [Member]
Ameren Energy Marketing Company [Member]
May 31, 2011
Period Three [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
May 31, 2010
Period Three [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
Apr. 30, 2012
Period Four [Member]
Ameren Energy Marketing Company [Member]
Apr. 30, 2010
Period Four [Member]
Ameren Energy Marketing Company [Member]
May 31, 2011
Period Four [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
Feb. 29, 2012
Period Six [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
Feb. 29, 2012
Period Seven [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
Apr. 30, 2012
Period Five [Member]
Ameren Energy Marketing Company [Member]
Feb. 29, 2012
Period Five [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
May 31, 2011
Period Five [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
Apr. 30, 2009
Period One [Member]
Ameren Energy Marketing Company [Member]
May 31, 2009
Period One [Member]
Ameren Illinois Company [Member]
Ameren Energy Marketing Company [Member]
MWh
Dec. 31, 2012
Guarantee Type, Other [Member]
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Buyer's Indemnification Guarantee Obligation, Period
 
 
 
 
 
 
 
 
 
 
 
24 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Business Acquisition Put Option Agreement Amount
 
 
 
 
 
 
$ 100 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Put Option Premium
 
 
 
 
 
 
2.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy Supply Agreements Amount
 
 
 
 
 
 
 
 
 
 
 
 
1 
9 
 
 
2 
8 
 
 
1 
3 
 
 
 
4 
 
 
4 
 
 
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power
 
 
 
 
 
 
 
 
 
 
 
 
 
 
924,000 
89,000 
 
 
1,747,200 
296,000 
 
 
1,840,800 
3,504,000 
1,317,600 
 
3,942,000 
650,000 
 
80,000 
 
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power, Rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
33 
48 
 
 
37 
40 
 
 
42 
32 
34 
 
30 
42 
 
48 
 
Intercompany Payables
 
 
 
 
 
 
 
 
5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Financing Receivable, Significant Purchases
 
 
 
 
 
 
 
 
35 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Purchases of Financing Receivable, Discount (less than $1 million)
 
 
 
 
 
 
 
 
1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Proceeds from Sale of Assets
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Gain (Loss) on Sales of Assets
 
 
 
 
 
 
 
2 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Guarantees Outstanding
354 
 
 
100 
189 
50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15 
Proceeds from Sale of Property, Plant, and Equipment
   
3 
7 
 
 
 
 
 
 
100 
37 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Guarantees, Maximum Exposure
 
 
 
 
25 
32 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of Credit Outstanding, Amount
9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Obligation to Provide Credit Support, Period
 
 
 
 
 
 
 
 
 
 
 
24 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Disposal Group, Including Discontinued Operation, Buyer's Indemnification Guarantee Obligation
 
 
 
 
 
 
 
 
 
 
 
$ 25 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commitments And Contingencies (Callaway Nuclear Energy Center) (Details) (USD $)
12 Months Ended
Dec. 31, 2012
Commitments and Contingencies [Line Items]
 
Insurance aggregate maximum coverage
$ 12,594,000,000 1
Insurance maximum coverage per incident
118,000,000 
Threshold for which a retrospective assessment for a covered loss is necessary
375,000,000 
Annual payment in the event of an incident at any licensed commercial reactor
17,500,000 
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act
118,000,000 
Maximum annual payment to be paid in a calendar year per reactor incident under liability provisions of Atomic Energy Act
17,500,000 
Amount of primary property liability coverage
500,000,000 
Amount of coverage in excess of primary property liability coverage
2,250,000,000 
Losses in excess of primary coverage
500,000,000 
Amount of weekly indemnity coverage commencing eight weeks after power outage
4,500,000 
Number of weeks of coverage after the first eight weeks of an outage
1 year 
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage
3,600,000 
Number of additional weeks after initial indemnity coverage for power outage, minimum
5 years 11 months 
Amount of weekly indemnity coverage thereafter not exceeding policy limit
490,000,000 
Amount of secondary weekly indemnity coverage for prolonged nuclear plant outage in excess of primary indemnity coverage
900,000 
Inflationary adjustment prescribed by most recent Price-Anderson Act renewal, in years
5 years 
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period
3,240,000,000 
Public Liability And Nuclear Worker Liability - American Nuclear Insurers [Member]
 
Commitments and Contingencies [Line Items]
 
Insurance aggregate maximum coverage
375,000,000 
Insurance maximum coverage per incident
0 
Public Liability And Nuclear Worker Liability - Pool Participation [Member]
 
Commitments and Contingencies [Line Items]
 
Insurance aggregate maximum coverage
12,219,000,000 2
Insurance maximum coverage per incident
118,000,000 3
Property Damage - Nuclear Electric Insurance Ltd [Member]
 
Commitments and Contingencies [Line Items]
 
Insurance aggregate maximum coverage
2,750,000,000 4
Insurance maximum coverage per incident
23,000,000 5
Replacement Power - Nuclear Electric Insurance Ltd [Member]
 
Commitments and Contingencies [Line Items]
 
Insurance aggregate maximum coverage
490,000,000 6
Insurance maximum coverage per incident
9,000,000 5
Replacement Power - Energy Risk Assurance Company [Member]
 
Commitments and Contingencies [Line Items]
 
Insurance aggregate maximum coverage
64,000,000 7
Insurance maximum coverage per incident
$ 0 
Commitments And Contingencies (Schedule Of Lease Obligations) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Commitments and Contingencies [Line Items]
 
 
 
Capital lease payments, 2013
$ 32 1
 
 
Capital lease payments, 2014
32 1
 
 
Capital lease payments, 2015
33 1
 
 
Capital lease payments, 2016
33 1
 
 
Capital lease payments, 2017
33 1
 
 
Capital lease payments, After 5 Years
425 1
 
 
Capital lease payments, Total
588 1
 
 
Less amount representing interest, 2013
27 
 
 
Less amount representing interest, 2014
27 
 
 
Less amount representing interest, 2015
27 
 
 
Less amount representing interest, 2016
27 
 
 
Less amount representing interest, 2017
27 
 
 
Less amount representing interest, After 5 Years
149 
 
 
Less amount representing interest, Total
284 
 
 
Present value of minimum capital lease payments, 2013
5 
 
 
Present value of minimum capital lease payments, 2014
5 
 
 
Present value of minimum capital lease payments, 2015
6 
 
 
Present value of minimum capital lease payments, 2016
6 
 
 
Present value of minimum capital lease payments, 2017
6 
 
 
Present value of minimum capital lease payments, After 5 Years
276 
 
 
Present value of minimum capital lease payments, Total
304 
 
 
Operating leases, 2013
19 2
 
 
Operating leases, 2014
14 2
 
 
Operating leases, 2015
14 2
 
 
Operating leases, 2016
14 2
 
 
Operating leases, 2017
14 2
 
 
Operating leases, After 5 Years
63 2
 
 
Operating leases, Total
138 2
 
 
Total lease obligations, 2013
24 
 
 
Total lease obligations, 2014
19 
 
 
Total lease obligations, 2015
20 
 
 
Total lease obligations, 2016
20 
 
 
Total lease obligations, 2017
20 
 
 
Total lease obligations, After 5 Years
339 
 
 
Total lease obligations, Total
442 
 
 
Annual obligation for real estate leases and railroad licenses
2 
 
 
Total rental expense
$ 33 
$ 36 
$ 41 
Commitments And Contingencies (Schedule Of Estimated Purchased Power Commitments) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
2013
$ 1,563 
2014
1,434 
2015
1,122 
2016
937 
2017
898 
Thereafter
1,659 
Total
7,613 
Coal [Member]
 
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
2013
620 
2014
625 
2015
614 
2016
644 
2017
676 
Thereafter
245 
Total
3,424 
Natural Gas [Member]
 
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
2013
327 
2014
249 
2015
136 
2016
54 
2017
34 
Thereafter
105 
Total
905 
Nuclear Fuel [Member]
 
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
2013
36 
2014
89 
2015
87 
2016
95 
2017
78 
Thereafter
277 
Total
662 
Purchased Power [Member]
 
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
2013
421 1
2014
309 1
2015
164 1
2016
78 1
2017
55 1
Thereafter
687 1
Total
1,714 1
Renewable energy credits agreements, term
20 years 
Methane Gas [Member]
 
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
2013
3 
2014
3 
2015
4 
2016
4 
2017
5 
Thereafter
99 
Total
118 
Other [Member]
 
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
2013
156 
2014
159 
2015
117 
2016
62 
2017
50 
Thereafter
246 
Total
790 
Ameren Illinois Company [Member]
 
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
 
Long-term purchase commitment, cubic feet to be purchased
15,500 
Gas transportation agreements, term
10 years 
Investment in Energy Efficiency Programs [Member] |
Union Electric Company [Member]
 
Long-term Purchase Commitment [Line Items]
 
Other commitment
$ 147 
Other commitments, term
3 years 
Commitments And Contingencies (Environmental Matters) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
state
Number of states participating in the cap-and-trade program
28 
Percent of top performing facilities
12.00% 
Estimated Capital Costs 2012 [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
$ 35 
Estimated Capital Costs 2012 [Member] |
Union Electric Company [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
105 
Estimated Capital Costs 2012 [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
30 
Estimated Capital Costs 2012 [Member] |
Ameren Energy Resources Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
5 
Newton Energy Center Scrubbers [Member] |
Newton Energy Center Estimated Capital Costs 2013 to 2017 [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
20 
Manufactured Gas Plant [Member]
 
Loss contingency range of possible loss, minimum
257.0 
Loss contingency range of possible loss, maximum
339.0 
Accrual for environmental loss contingencies
257.0 1
Manufactured Gas Plant [Member] |
Ameren Illinois Company [Member]
 
Number of remediation sites
44 
Former Coal Ash Landfill [Member] |
Ameren Illinois Company [Member]
 
Loss contingency range of possible loss, minimum
0.5 
Loss contingency range of possible loss, maximum
6.0 
Accrual for environmental loss contingencies
0.5 
Other Environmental [Member] |
Ameren Illinois Company [Member]
 
Accrual for environmental loss contingencies
0.8 
Former Coal Tar Distillery [Member] |
Union Electric Company [Member]
 
Loss contingency range of possible loss, minimum
2.0 
Loss contingency range of possible loss, maximum
5.0 
Accrual for environmental loss contingencies
2.0 
Sauget Area 2 [Member] |
Union Electric Company [Member]
 
Loss contingency range of possible loss, minimum
0.3 
Loss contingency range of possible loss, maximum
10.0 
Accrual for environmental loss contingencies
0.3 
Substation in St Charles, Missouri [Member] |
Union Electric Company [Member]
 
Loss contingency range of possible loss, minimum
1.5 
Loss contingency range of possible loss, maximum
2.3 
Accrual for environmental loss contingencies
1.5 
Minimum [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
395 
Minimum [Member] |
Union Electric Company [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
1,115 
Minimum [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
350 
Minimum [Member] |
Ameren Energy Resources Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
45 
Minimum [Member] |
Estimated Capital Costs 2014 to 2017 [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
120 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
150 
Minimum [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Union Electric Company [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
215 
Minimum [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
100 
Minimum [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Ameren Energy Resources Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
20 
Minimum [Member] |
Estimated Capital Costs 2018 to 2022 [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
240 
Minimum [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Union Electric Company [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
795 
Minimum [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
220 
Minimum [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Ameren Energy Resources Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
20 
Maximum [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
480 
Maximum [Member] |
Union Electric Company [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
1,340 
Maximum [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
425 
Maximum [Member] |
Ameren Energy Resources Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
55 
Maximum [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Union Electric Company [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
260 
Maximum [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
125 
Maximum [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Ameren Energy Resources Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
25 
Maximum [Member] |
Estimated Capital Costs 2018 to 2022 [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
295 
Maximum [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Union Electric Company [Member]
 
Estimated Capital Costs To Comply With Existing And Known Federal And State Environmental Regulations
975 
Maximum [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Ameren Energy Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
270 
Maximum [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Ameren Energy Resources Generating Company [Member]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
$ 25 
Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Details) (Union Electric Company [Member], USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Union Electric Company [Member]
 
Commitments and Contingencies [Line Items]
 
Insurance Settlements Receivable
$ 68 
Divestiture Transactions and Discontinued Operations (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended 6 Months Ended 12 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended 3 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Mar. 14, 2013
New Ameren Energy Resources Company, LLC [Member]
Jun. 30, 2013
New Ameren Energy Resources Company, LLC [Member]
Dec. 31, 2012
New Ameren Energy Resources Company, LLC [Member]
Dec. 31, 2012
Notes Payable, Other Payables [Member]
New Ameren Energy Resources Company, LLC [Member]
Dec. 31, 2012
Illinois Power Holdings, LLC [Member]
Dec. 31, 2012
Elgin, Gibson City and Grand Tower Energy Centers [Member]
Dec. 31, 2012
Merchant Generation [Member]
Dec. 31, 2011
Merchant Generation [Member]
Dec. 31, 2010
Merchant Generation [Member]
Mar. 31, 2012
Merchant Generation [Member]
Duck Creek Energy Center [Member]
Dec. 31, 2010
Medina Valley Energy Center [Member]
Dec. 31, 2010
SO2 Emission Allowances [Member]
Merchant Generation [Member]
Jun. 30, 2013
Claimed Manufacturing Exemptions And Credits [Member]
Merchant Generation [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and other postretirement obligations assumed by counterparty
 
 
 
 
 
$ 40 
 
$ 40 
 
 
 
 
 
 
 
 
Defined benefit plan assets assumed by counterparty
 
 
 
 
 
15 
 
15 
 
 
 
 
 
 
 
 
Asset retirement obligation
375 1
369 1 2
403 1
 
 
26 
 
 
 
 
 
 
 
 
 
 
Converted instrument, period for conversion
 
 
 
 
 
 
24 months 
 
 
 
 
 
 
 
 
 
Cash collateral for borrowed securities
 
 
 
 
 
27 
 
 
 
 
 
 
 
 
 
 
Aggregate principal amount of senior notes
 
 
 
825 
 
 
 
 
 
 
 
 
 
 
 
 
Transaction agreement, cash retained by counterparty
 
 
 
85 
 
 
 
 
 
 
 
 
 
 
 
 
Transaction agreement, closing extension period
 
 
 
1 month 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation to provide credit support, period
 
 
 
24 months 
 
 
 
 
 
 
 
 
 
 
 
 
Buyer's indemnification guarantee obligation
 
 
 
25 
 
 
 
 
 
 
 
 
 
 
 
 
Buyer's indemnification guarantee obligation, period
 
 
 
24 months 
 
 
 
 
 
 
 
 
 
 
 
 
Period for working capital adjustment
 
 
 
120 days 
 
 
 
 
 
 
 
 
 
 
 
 
Transitional services to be provided to buyer, period
 
 
 
12 months 
 
 
 
 
 
 
 
 
 
 
 
 
Transitional services to be provided to buyer at no charge, period
 
 
 
90 days 
 
 
 
 
 
 
 
 
 
 
 
 
Transitional services to be provided to buyer at no charge, maximum amount
 
 
 
5 
 
 
 
 
 
 
 
 
 
 
 
 
Transitional services to be provided to buyer, additional period
 
 
 
6 months 
 
 
 
 
 
 
 
 
 
 
 
 
Impairment of assets to be disposed of
 
 
 
 
168 
 
 
 
 
1,950 
2 
420 
628 
36 
68 
 
Disposal group, fair value
 
 
 
 
 
 
 
 
133 
 
 
 
 
 
 
 
Discontinued operations deferred tax expense
 
 
 
 
97 
 
 
 
 
 
 
 
 
 
 
 
Discontinued operations deferred tax benefit
 
 
 
 
69 
 
 
 
 
 
 
 
 
 
 
 
Tax payment, settlement resolution
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 7 
Divestiture Transactions and Discontinued Operations (Components of Discontinued Operations in Consolidated Statement of Income) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 6 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Jun. 30, 2013
New Ameren Energy Resources Company, LLC [Member]
Dec. 31, 2012
Merchant Generation [Member]
Dec. 31, 2011
Merchant Generation [Member]
Dec. 31, 2010
Merchant Generation [Member]
Mar. 31, 2012
Merchant Generation [Member]
Duck Creek Energy Center [Member]
Dec. 31, 2010
Medina Valley Energy Center [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
Operating revenues
$ 1,047 
$ 1,278 
$ 1,369 
 
 
 
 
 
 
Operating expenses
(3,478)1
(1,048)
(1,578)2
 
 
 
 
 
 
Operating income (loss)
(2,431)
230 
(209)
 
 
 
 
 
 
Other income (loss)
   
1 
2 
 
 
 
 
 
 
Interest charges
(56)
(64)
(83)
 
 
 
 
 
 
Income (loss) before income taxes
(2,487)
167 
(290)
 
 
 
 
 
 
Income tax (expense) benefit
989 
(65)
(51)
 
 
 
 
 
 
Income (loss) from discontinued operations, net of taxes
(1,498)
102 
(341)
 
 
 
 
 
 
Impairment of assets to be disposed of
 
 
 
168 
1,950 
2 
420 
628 
36 
Impairment of Long-Lived Assets Held-for-use
0 
123 
64 
 
 
 
 
 
 
Property, Plant and Equipment, Net
$ 15,348 3
$ 14,848 3
 
 
 
 
 
 
 
Divestiture Transactions and Discontinued Operations (Components of Assets and Liabilities on Consolidated Balance Sheet) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Current assets of discontinued operations
 
 
 
Cash and cash equivalents
$ 25 
$ 7 
$ 7 
Accounts receivable and unbilled revenue
102 
108 
 
Materials and supplies
134 
162 
 
Mark-to-market derivative assets
102 
65 
 
Property and plant, net
748 
3,279 
 
Accumulated deferred income taxes, net
385 
   
 
Other assets
104 
97 
 
Total current assets of discontinued operations
1,600 
3,718 
 
Current liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
133 
134 
 
Mark-to-market derivative liabilities
63 
39 
 
Long-term debt, net
824 
824 
 
Accumulated deferred income taxes, net
   
583 
 
Asset retirement obligations
78 
64 
 
Pension and other postretirement benefits
40 
92 
 
Other liabilities
28 
26 
 
Total current liabilities of discontinued operations
1,166 
1,762 
 
Accumulated other comprehensive income (loss)
19 1
(31)1
 
Noncontrolling Interest
$ 8 2
$ 7 2
 
Electric Energy, Inc [Member]
 
 
 
Current liabilities of discontinued operations
 
 
 
Percentage of EEI not owned by Ameren
20.00% 
 
 
Divestiture Transactions and Discontinued Operations (Debt Ratios) (Details) (Ameren Energy Generating Company [Member])
12 Months Ended
Dec. 31, 2012
Minimum Required Ratio [Member]
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
Interest coverage ratio, restricted payment
1.75 1
Interest coverage ratio, additional indebtedness
2.5 2
Debt-to-capital ratio, additional indebtedness
0.60 2
Actual Ratio [Member]
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
Interest coverage ratio, restricted payment
2.6 1
Interest coverage ratio, additional indebtedness
2.6 2
Debt-to-capital ratio, additional indebtedness
0.44 2
Impairment and Other Charges (Summary Of Goodwill And Other Asset Impairment Pretax Charges) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Impairment and Other Charges [Line Items]
 
 
 
Impairment charge on long-lived assets and related charges
$ 0 
$ 123 
$ 64 
Total impairment charge
    
$ 123 
$ 64 
Impairment and Other Charges (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 1 Months Ended 12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2011
Closure of Meredosia and Hutsonville Energy Centers [Member]
Dec. 31, 2011
Taum Sauk Energy Center [Member]
Union Electric Company [Member]
Dec. 31, 2010
Meredosia Energy Center [Member]
Impairment and Other Charges [Line Items]
 
 
 
 
 
 
Impairment charge on long-lived assets and related charges
$ 0 
$ 123 
$ 64 
$ 26 
 
$ 64 
Non-cash impairment of materials and supplies
 
 
 
4 
 
 
Severance costs
 
 
 
4 
 
 
Loss from regulatory disallowance
 
 
 
 
$ 89 
 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
segment
Dec. 31, 2011
Dec. 31, 2010
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Number of reportable segments
 
 
 
 
 
 
 
 
3 
 
 
External revenues
$ 1,258 1
$ 1,709 1
$ 1,402 1
$ 1,412 1
$ 1,296 1
$ 1,876 1
$ 1,458 1
$ 1,597 1
$ 5,781 
$ 6,227 
$ 6,269 
Depreciation and amortization
 
 
 
 
 
 
 
 
667 
646 
627 
Interest and dividend income
 
 
 
 
 
 
 
 
4 2
3 
4 
Interest Expense
 
 
 
 
 
 
 
 
391 
387 
415 
Income taxes (benefit)
 
 
 
 
 
 
 
 
309 
245 
274 
Income (Loss) from Continuing Operations Attributable to Parent
15 1
305 1
161 1
37 1
(1)1
265 1
116 1
38 1
518 
418 
483 
Capital expenditures
 
 
 
 
 
 
 
 
1,063 
881 
941 
TOTAL ASSETS
22,219 
 
 
 
23,723 
 
 
 
22,219 
23,723 
 
Impairment and other charges
 
 
 
 
 
 
 
 
   
123 
64 
Union Electric Company [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
External revenues
 
 
 
 
 
 
 
 
3,252 
3,360 
3,180 
Intersegment revenues
 
 
 
 
 
 
 
 
20 
23 
17 
Depreciation and amortization
 
 
 
 
 
 
 
 
440 
408 
382 
Interest and dividend income
 
 
 
 
 
 
 
 
32 
30 
31 
Interest Expense
 
 
 
 
 
 
 
 
223 
209 
213 
Income taxes (benefit)
 
 
 
 
 
 
 
 
252 
161 
199 
Income (Loss) from Continuing Operations Attributable to Parent
 
 
 
 
 
 
 
 
416 
287 
364 
Capital expenditures
 
 
 
 
 
 
 
 
595 
550 
624 
TOTAL ASSETS
13,043 
 
 
 
12,757 
 
 
 
13,043 
12,757 
12,504 
Ameren Illinois Company [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
External revenues
 
 
 
 
 
 
 
 
2,524 
2,784 
3,012 
Intersegment revenues
 
 
 
 
 
 
 
 
1 
3 
2 
Depreciation and amortization
 
 
 
 
 
 
 
 
221 
215 
210 
Interest and dividend income
 
 
 
 
 
 
 
 
 
1 
1 
Interest and dividend income
 
 
 
 
 
 
 
 
   
 
 
Interest Expense
 
 
 
 
 
 
 
 
129 
136 
143 
Income taxes (benefit)
 
 
 
 
 
 
 
 
94 
127 
137 
Income (Loss) from Continuing Operations Attributable to Parent
 
 
 
 
 
 
 
 
141 
193 
208 
Capital expenditures
 
 
 
 
 
 
 
 
442 
351 
281 
TOTAL ASSETS
7,282 
 
 
 
7,213 
 
 
 
7,282 
7,213 
7,406 
Other Segment [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
External revenues
 
 
 
 
 
 
 
 
5 
83 
77 
Intersegment revenues
 
 
 
 
 
 
 
 
3 
3 
   
Depreciation and amortization
 
 
 
 
 
 
 
 
6 
23 
35 
Interest and dividend income
 
 
 
 
 
 
 
 
   
   
   
Interest Expense
 
 
 
 
 
 
 
 
39 
42 
59 
Income taxes (benefit)
 
 
 
 
 
 
 
 
(37)
(43)
(62)
Income (Loss) from Continuing Operations Attributable to Parent
 
 
 
 
 
 
 
 
(39)
(62)
(89)
Capital expenditures
 
 
 
 
 
 
 
 
26 
(20)3
36 
TOTAL ASSETS
1,228 
 
 
 
1,211 
 
 
 
1,228 
1,211 
1,354 
Intersegment Elimination [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Intersegment revenues
 
 
 
 
 
 
 
 
(24)
(29)
(19)
Interest and dividend income
 
 
 
 
 
 
 
 
   
   
   
Interest Expense
 
 
 
 
 
 
 
 
   
   
   
TOTAL ASSETS
(934)
 
 
 
(1,176)
 
 
 
(934)
(1,176)
(1,541)
Segment, Continuing Operations [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
External revenues
 
 
 
 
 
 
 
 
5,781 
6,227 
6,269 
Depreciation and amortization
 
 
 
 
 
 
 
 
667 
646 
627 
Interest and dividend income
 
 
 
 
 
 
 
 
32 
31 
32 
Interest Expense
 
 
 
 
 
 
 
 
391 
387 
415 
Income taxes (benefit)
 
 
 
 
 
 
 
 
309 
245 
274 
Income (Loss) from Continuing Operations Attributable to Parent
 
 
 
 
 
 
 
 
 
418 
483 
Capital expenditures
 
 
 
 
 
 
 
 
1,063 
881 
941 
TOTAL ASSETS
$ 20,619 4
 
 
 
$ 20,005 4
 
 
 
$ 20,619 4
$ 20,005 4
$ 19,723 4
Selected Quarterly Information (Summary Of Selected Quarterly Information) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended 3 Months Ended 6 Months Ended 9 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Mar. 31, 2012
Classification of Activity from Nuclear Decommissioning Trust Fund [Member]
Jun. 30, 2012
Classification of Activity from Nuclear Decommissioning Trust Fund [Member]
Sep. 30, 2012
Classification of Activity from Nuclear Decommissioning Trust Fund [Member]
Selected Quarterly Financial Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 1,258 1
$ 1,709 1
$ 1,402 1
$ 1,412 1
$ 1,296 1
$ 1,876 1
$ 1,458 1
$ 1,597 1
$ 5,781 
$ 6,227 
$ 6,269 
 
 
 
Operating Income
111 1 2
578 1 2
344 1 2
158 1 2
91 1 2
494 1 2
270 1 2
156 1 2
1,191 
1,011 
1,125 
 
 
 
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest
(1,155)1
374 1
210 1
(403)1
26 1
287 1
139 1
74 1
(974)
526 
151 
 
 
 
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations
15 1
305 1
161 1
37 1
(1)1
265 1
116 1
38 1
518 
418 
483 
 
 
 
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations
(1,171)1
69 1
50 1
(440)1
26 1
20 1
22 1
33 1
(1,492)
101 
(344)
 
 
 
Net income (Loss) Attributable to Ameren Corporation
(1,156)1
374 1
211 1
(403)1
25 1
285 1
138 1
71 1
(974)
519 
139 
 
 
 
Earnings (Loss) per Common Share - Basic and Diluted - Continuing Operations
$ 0.06 1
$ 1.26 1
$ 0.66 1
$ 0.15 1
$ (0.01)1
$ 1.10 1
$ 0.48 1
$ 0.16 1
$ 2.13 
$ 1.73 
$ 2.02 
 
 
 
Earnings (Loss) per Common Share - Basic and Diluted - Discontinued Operations
$ (4.82)1
$ 0.28 1
$ 0.21 1
$ (1.81)1
$ 0.11 1
$ 0.08 1
$ 0.09 1
$ 0.13 1
$ (6.14)
$ 0.42 
$ (1.44)
 
 
 
Earnings (Loss) per Common Share - Basic and Diluted
$ (4.76)1
$ 1.54 1
$ 0.87 1
$ (1.66)1
$ 0.10 1
$ 1.18 1
$ 0.57 1
$ 0.29 1
$ (4.01)
$ 2.15 
$ 0.58 
 
 
 
Impairment and other charges
 
 
 
 
 
 
 
 
   
123 
64 
 
 
 
Quantifying Misstatement in Current Year Financial Statements, Amount
 
 
 
 
 
 
 
 
 
 
 
$ 14 
$ 26 
$ 49 
Schedule I - Condensed Financial Information Of Parent (Statement of Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2012
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Dec. 31, 2011
Sep. 30, 2011
Jun. 30, 2011
Mar. 31, 2011
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 1,258 1
$ 1,709 1
$ 1,402 1
$ 1,412 1
$ 1,296 1
$ 1,876 1
$ 1,458 1
$ 1,597 1
$ 5,781 
$ 6,227 
$ 6,269 
Impairment and other charges
 
 
 
 
 
 
 
 
   
123 
64 
Operating expenses
 
 
 
 
 
 
 
 
4,590 
5,216 
5,144 
Operating Income
111 1 2
578 1 2
344 1 2
158 1 2
91 1 2
494 1 2
270 1 2
156 1 2
1,191 
1,011 
1,125 
Interest income from affiliates
 
 
 
 
 
 
 
 
4 3
3 
4 
Miscellaneous expense
 
 
 
 
 
 
 
 
70 
68 
88 
Other Nonoperating Expense
 
 
 
 
 
 
 
 
37 
23 
32 
Interest charges
 
 
 
 
 
 
 
 
(391)
(387)
(415)
Income tax (benefit)
 
 
 
 
 
 
 
 
309 
245 
274 
Continuing Operations
15 1
305 1
161 1
37 1
(1)1
265 1
116 1
38 1
518 
418 
483 
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent
(1,171)1
69 1
50 1
(440)1
26 1
20 1
22 1
33 1
(1,492)
101 
(344)
Net income (Loss) Attributable to Ameren Corporation
(1,156)1
374 1
211 1
(403)1
25 1
285 1
138 1
71 1
(974)
519 
139 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $6, $14, and $(7), respectively
 
 
 
 
 
 
 
 
(8)
(19)
10 
Comprehensive Income (Loss) from Continuing Operations, Net of Tax, Portion Attributable to Parent
 
 
 
 
 
 
 
 
510 
399 
493 
Comprehensive Income from Continuing Operations
 
 
 
 
 
 
 
 
(932)
486 
135 
Other Comprehensive Income (Loss), Taxes:
 
 
 
 
 
 
 
 
 
 
 
Pension and other postretirement activity, tax (benefit)
 
 
 
 
 
 
 
 
(6)
(14)
6 
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
 
 
 
 
 
 
 
 
58 
(20)
(16)
Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Portion Attributable to Parent
 
 
 
 
 
 
 
 
(1,442)
87 
(358)
Parent Company [Member]
 
 
 
 
 
 
 
 
 
 
 
Condensed Financial Statements, Captions [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
   
   
   
Impairment and other charges
 
 
 
 
 
 
 
 
   
   
   
Operating expenses
 
 
 
 
 
 
 
 
17 
13 
19 
Operating Income
 
 
 
 
 
 
 
 
(17)
(13)
(19)
Equity in earnings of subsidiaries
 
 
 
 
 
 
 
 
548 
451 
525 
Interest income from affiliates
 
 
 
 
 
 
 
 
3 
5 
8 
Other Nonoperating Expense
 
 
 
 
 
 
 
 
4 
4 
3 
Interest charges
 
 
 
 
 
 
 
 
(39)
(41)
(56)
Income tax (benefit)
 
 
 
 
 
 
 
 
(27)
(20)
(28)
Continuing Operations
 
 
 
 
 
 
 
 
518 
418 
483 
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent
 
 
 
 
 
 
 
 
(1,492)
101 
(344)
Net income (Loss) Attributable to Ameren Corporation
 
 
 
 
 
 
 
 
(974)
519 
139 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $6, $14, and $(7), respectively
 
 
 
 
 
 
 
 
(8)
(19)
10 
Comprehensive Income (Loss) from Continuing Operations, Net of Tax, Portion Attributable to Parent
 
 
 
 
 
 
 
 
510 
399 
493 
Comprehensive Income from Continuing Operations
 
 
 
 
 
 
 
 
(932)
486 
135 
Other Comprehensive Income (Loss), Taxes:
 
 
 
 
 
 
 
 
 
 
 
Unrealized net gain (loss) on derivative hedging instruments, tax (benefit)
 
 
 
 
 
 
 
 
12 
1 
(1)
Reclassification adjustments for derivative (gain) included in net income, tax
 
 
 
 
 
 
 
 
1 
(3)
5 
Pension and other postretirement activity, tax (benefit)
 
 
 
 
 
 
 
 
22 
(32)
6 
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest
 
 
 
 
 
 
 
 
50 
(14)
(14)
Comprehensive Income (Loss) from Discontinued Operations, Net of Tax, Portion Attributable to Parent
 
 
 
 
 
 
 
 
$ (1,442)
$ 87 
$ (358)
Schedule I - Condensed Financial Information Of Parent (Balance Sheet) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
ASSETS
 
 
 
 
Cash and cash equivalents
$ 184 
$ 248 
$ 538 
 
Accounts and notes receivable - affiliates
354 
424 
 
 
Other current assets
98 
151 
 
 
Total current assets
3,585 
5,737 
 
 
Other non-current assets
667 
760 
 
 
TOTAL ASSETS
22,219 
23,723 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Short-term debt
   
148 
 
 
Other current liabilities
168 
195 
 
 
Total current liabilities
2,660 
3,373 
 
 
Long-term debt
5,802 
5,853 
 
 
Other deferred credits and liabilities
642 
424 
 
 
Commitments and Contingencies
   
   
 
 
Retained earnings
1,006 
2,369 
 
 
Accumulated other comprehensive income (loss)
(8)
(50)
 
 
Total equity
6,767 
8,068 
7,884 
 
TOTAL LIABILITIES AND EQUITY
22,219 
23,723 
 
 
Parent Company [Member]
 
 
 
 
ASSETS
 
 
 
 
Cash and cash equivalents
23 
3 
4 
24 
Advances to money pool
316 
340 
 
 
Accounts and notes receivable - affiliates
31 
57 
 
 
Other current assets
49 
   
 
 
Total current assets
419 
400 
 
 
Investments in subsidiaries - continuing operations
6,288 
6,327 
 
 
Equity Method Investments - Discontinued Operations
(326)
1,155 
 
 
Note receivable - affiliates
462 
425 
 
 
Other non-current assets
320 
333 
 
 
TOTAL ASSETS
7,163 
8,640 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Short-term debt
   
148 
 
 
Accounts payable - affiliates
10 
13 
 
 
Other current liabilities
33 
62 
 
 
Total current liabilities
43 
223 
 
 
Long-term debt
424 
424 
 
 
Other deferred credits and liabilities
80 
74 
 
 
Total liabilities
547 
721 
 
 
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6
2 
2 
 
 
Other paid-in capital, principally premium on common stock
5,616 
5,598 
 
 
Retained earnings
1,006 
2,369 
 
 
Accumulated other comprehensive income (loss)
(8)
(50)
 
 
Total equity
6,616 
7,919 
 
 
TOTAL LIABILITIES AND EQUITY
$ 7,163 
$ 8,640 
 
 
Schedule I - Condensed Financial Information Of Parent (Statement of Cash Flows) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
 
 
 
Net cash provided by operating activities
$ 1,690 
$ 1,878 
$ 1,823 
Cash Flows From Investing Activities:
 
 
 
Other
2 
12 
2 
Net cash used in investing activities
(1,310)
(1,048)
(1,096)
Cash flows from financing activities:
 
 
 
Dividends on common stock
(382)
(375)
(368)
Short-term debt and credit facility borrowings, net
(148)
(481)
(221)
Issuances:
 
 
 
Long-term debt
882 
   
   
Common stock
   
65 
80 
Net cash provided by (used in) financing activities
(426)
(1,120)
(804)
Net change in cash and cash equivalents
(46)
(290)
(77)
Cash and cash equivalents at beginning of year
248 
538 
 
Cash and cash equivalents at end of year
184 
248 
538 
Noncash financing activity – dividends on common stock
(7)
   
   
Parent Company [Member]
 
 
 
Condensed Financial Statements, Captions [Line Items]
 
 
 
Net cash provided by operating activities
532 
804 
241 
Cash Flows From Investing Activities:
 
 
 
Money pool advances, net
24 
(276)
18 
Intercompany notes receivable, net
(20)
358 
242 
Investments in subsidiaries
(2)
(94)
(13)
Return of investments
21 
3 
1 
Other
(5)
(5)
   
Net cash used in investing activities
18 
(14)
248 
Cash flows from financing activities:
 
 
 
Dividends on common stock
(382)
(375)
(368)
Short-term debt and credit facility borrowings, net
(148)
(481)
(221)
Issuances:
 
 
 
Common stock
   
65 
80 
Net cash provided by (used in) financing activities
(530)
(791)
(509)
Net change in cash and cash equivalents
20 
(1)
(20)
Cash and cash equivalents at beginning of year
3 
4 
24 
Cash and cash equivalents at end of year
23 
3 
4 
Cash dividends received from consolidated subsidiaries
610 
730 
368 
Noncash financing activity – dividends on common stock
$ (7)
    
    
Schedule I - Condensed Financial Information Of Parent (Impairment and Other Charges) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Impairment and Other Charges [Line Items]
 
 
 
Impairment charge on long-lived assets and related charges
$ 0 
$ 123 
$ 64 
Parent Company [Member] |
Merchant Generation [Member]
 
 
 
Impairment and Other Charges [Line Items]
 
 
 
Impairment charge on long-lived assets and related charges
$ 1,880 
 
 
Schedule I - Condensed Financial Information Of Parent Basis of Presentation Parent Company (Details) (Merchant Generation [Member], Parent Company [Member], USD $)
In Millions, unless otherwise specified
0 Months Ended
Mar. 14, 2013
Merchant Generation [Member] |
Parent Company [Member]
 
Condensed Financial Statements, Captions [Line Items]
 
Proceeds from Sales of Business, Affiliate and Productive Assets
$ 100 
Schedule II - Valuation And Qualifying Accounts (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Allowance For Doubtful Accounts [Member]
 
 
 
Valuation and Qualifying Accounts Disclosure [Line Items]
 
 
 
Balance at Beginning of Period
$ 20 
$ 22 
$ 24 
Charged to Costs and Expenses
30 
41 
32 
Charged to Other Accounts
2 1
   1
   1
Deductions
35 2
43 2
34 2
Balance at End of Period
17 
20 
22 
Valuation Allowance of Deferred Tax Assets [Member]
 
 
 
Valuation and Qualifying Accounts Disclosure [Line Items]
 
 
 
Balance at Beginning of Period
1 
1 
   
Charged to Costs and Expenses
1 
   
1 
Charged to Other Accounts
   
   
   
Deductions
   
   
   
Balance at End of Period
$ 2 
$ 1 
$ 1