UNION ELECTRIC CO, 10-Q filed on 8/9/2013
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2013
Jul. 31, 2013
Entity Information [Line Items]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Jun. 30, 2013 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q2 
 
Trading Symbol
AEE 
 
Entity Registrant Name
AMEREN CORP 
 
Entity Central Index Key
0001002910 
 
Current Fiscal Year End Date
--06-30 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
242,634,671 
Union Electric Company [Member]
 
 
Entity Information [Line Items]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Jun. 30, 2013 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q2 
 
Entity Registrant Name
UNION ELECTRIC CO 
 
Entity Central Index Key
0000100826 
 
Current Fiscal Year End Date
--06-30 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
102,123,834 
Ameren Illinois Company [Member]
 
 
Entity Information [Line Items]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Jun. 30, 2013 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q2 
 
Entity Registrant Name
AMEREN ILLINOIS CO 
 
Entity Central Index Key
0000018654 
 
Current Fiscal Year End Date
--06-30 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
25,452,373 
Consolidated Statement of Income (Loss) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Operating Revenues:
 
 
 
 
Electric
$ 1,228 
$ 1,255 
$ 2,316 
$ 2,319 
Gas
175 
147 
562 
495 
Total operating revenues
1,403 
1,402 
2,878 
2,814 
Operating Expenses:
 
 
 
 
Fuel
213 
175 
426 
356 
Purchased power
121 
161 
272 
370 
Gas purchased for resale
72 
49 
302 
264 
Other operations and maintenance
447 
395 
846 
764 
Depreciation and amortization
178 
168 
353 
335 
Taxes other than income taxes
111 
110 
233 
223 
Total operating expenses
1,142 
1,058 
2,432 
2,312 
Operating Income
261 
344 
446 
502 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
16 1
19 1
31 1
36 1
Miscellaneous expense
5 1
7 1
13 1
22 1
Total other income (expense)
11 
12 
18 
14 
Interest Charges
100 
98 
201 
196 
Income Before Income Taxes
172 
258 
263 
320 
Income Taxes
66 
96 
101 
119 
Income from Continuing Operations
106 
162 
162 
201 
Income (Loss) from Discontinued Operations, Net of Taxes (Note 2)
(10)
48 
(209)
(394)
Net Income (Loss)
96 
210 
(47)
(193)
Pension and other postretirement benefit plan activity, net of income taxes (benefit)
10 
1 
10 
1 
Comprehensive Income (Loss)
101 
216 
(51)
(172)
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
 
 
 
 
Continuing Operations
1 
1 
3 
3 
Discontinued Operations
   
(2)
   
(4)
Net Income (Loss):
 
 
 
 
Continuing Operations
105 
161 
159 
198 
Discontinued Operations
(10)
50 
(209)
(390)
Net Income (Loss)
95 
211 
(50)
(192)
Earnings (Loss) per Common Share – Basic and Diluted:
 
 
 
 
Continuing Operations (in dollars per share)
$ 0.44 
$ 0.66 
$ 0.66 
$ 0.81 
Discontinued Operations (in dollars per share)
$ (0.05)
$ 0.21 
$ (0.87)
$ (1.60)
Net Income (Loss) per Common Share - Basic and Diluted
$ 0.39 
$ 0.87 
$ (0.21)
$ (0.79)
Dividends per Common Share
$ 0.40 
$ 0.40 
$ 0.80 
$ 0.80 
Average Common Shares Outstanding
242.6 
242.6 
242.6 
242.6 
Union Electric Company [Member]
 
 
 
 
Operating Revenues:
 
 
 
 
Electric
860 
822 
1,592 
1,458 
Gas
29 
21 
93 
76 
Other
   
1.0 
   
1.0 
Total operating revenues
889 
844 
1,685 
1,535 
Operating Expenses:
 
 
 
 
Fuel
213 
177 
426 
357 
Purchased power
41 
   
67 
20 
Gas purchased for resale
11 
5 
48 
37 
Other operations and maintenance
253 
206 
474 
408 
Depreciation and amortization
113 
109 
224 
217 
Taxes other than income taxes
79 
78 
156 
149 
Total operating expenses
710 
575 
1,395 
1,188 
Operating Income
179 
269 
290 
347 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
14 
18 
28 
33 
Miscellaneous expense
3 
4 
8 
7 
Total other income (expense)
11 
14 
20 
26 
Interest Charges
56 
56 
116 
112 
Income Before Income Taxes
134 
227 
194 
261 
Income Taxes
49 
83 
68 
95 
Net Income (Loss)
85 
144 
126 
166 
Other Comprehensive Income
0 
0 
0 
0 
Comprehensive Income (Loss)
85 
144 
126 
166 
Net Income (Loss):
 
 
 
 
Net Income (Loss)
85 
144 
126 
166 
Earnings (Loss) per Common Share – Basic and Diluted:
 
 
 
 
Preferred Stock Dividends
1 
1 
2 
2 
Net Income Available to Common Stockholder
84 
143 
124 
164 
Ameren Illinois Company [Member]
 
 
 
 
Operating Revenues:
 
 
 
 
Electric
368 
437 
728 
868 
Gas
146 
127 
470 
420 
Other
2.0 
   
2.0 
   
Total operating revenues
516 
564 
1,200 
1,288 
Operating Expenses:
 
 
 
 
Purchased power
80 
162 
207 
352 
Gas purchased for resale
61 
44 
254 
227 
Other operations and maintenance
196 
186 
372 
354 
Depreciation and amortization
62 
55 
123 
110 
Taxes other than income taxes
30 
31 
72 
70 
Total operating expenses
429 
478 
1,028 
1,113 
Operating Income
87 
86 
172 
175 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
2 
2 
3 
3 
Miscellaneous expense
1 
2 
4 
13 
Total other income (expense)
1 
   
(1)
(10)
Interest Charges
34 
31 
65 
64 
Income Before Income Taxes
54 
55 
106 
101 
Income Taxes
22 
22 
42 
40 
Net Income (Loss)
32 
33 
64 
61 
Pension and other postretirement benefit plan activity, net of income taxes (benefit)
(1)
(1)
(2)
(2)
Comprehensive Income (Loss)
31 
32 
62 
59 
Net Income (Loss):
 
 
 
 
Net Income (Loss)
32 
33 
64 
61 
Earnings (Loss) per Common Share – Basic and Diluted:
 
 
 
 
Preferred Stock Dividends
1 
1 
2 
2 
Net Income Available to Common Stockholder
$ 31 
$ 32 
$ 62 
$ 59 
Consolidated Statement of Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Pension and other postretirement benefit plan activity, tax expense (benefit)
$ 8 
$ 0 
$ 8 
$ 0 
Ameren Illinois Company [Member]
 
 
 
 
Pension and other postretirement benefit plan activity, tax expense (benefit)
$ 0 
$ (1)
$ (1)
$ (1)
Consolidated Statement of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Income from Continuing Operations
$ 106 
$ 162 
$ 162 
$ 201 
Other Comprehensive Income, Net of Taxes
 
 
 
 
Pension and other postretirement benefit plan activity, net of income taxes (benefit)
10 
1 
10 
1 
Pension and other postretirement benefit plan activity, tax expense (benefit)
8 
0 
8 
0 
Other Comprehensive Income, Net of Taxes
10 
1 
10 
1 
Comprehensive Income from Continuing Operations
116 
163 
172 
202 
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests
1 
1 
3 
3 
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation
115 
162 
169 
199 
Net Income (Loss) from Discontinued Operations
(10)
48 
(209)
(394)
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Taxes
(4)
4 
(11)
19 
Comprehensive Income (Loss) from Discontinued Operations
(14)
52 
(220)
(375)
Less: Comprehensive Loss from Discontinued Operations Attributable to Noncontrolling Interest
0 
(2)
0 
(4)
Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation
(14)
54 
(220)
(371)
Comprehensive Income (Loss)
$ 101 
$ 216 
$ (51)
$ (172)
Consolidated Balance Sheet (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Current Assets:
 
 
Cash and cash equivalents
$ 150 
$ 184 
Accounts receivable - trade (less allowance for doubtful accounts)
425 
354 
Unbilled revenue
308 
291 
Miscellaneous accounts and notes receivable
75 
71 
Materials and supplies
511 
570 
Current regulatory assets
192 
247 
Current accumulated deferred income taxes, net
157 
160 
Other current assets
104 
98 
Current assets of discontinued operations
1,486 
1,600 
Total current assets
3,408 
3,575 
Property and Plant, Net
15,601 
15,348 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
442 
408 
Goodwill
411 
411 
Intangible assets
18 
14 
Regulatory assets
1,742 
1,786 
Other assets
654 
667 
Total investments and other assets
3,267 
3,286 
TOTAL ASSETS
22,276 
22,209 
Current Liabilities:
 
 
Current maturities of long-term debt
884 
355 
Short-term debt
25 
   
Accounts and wages payable
428 
533 
Taxes accrued
123 
50 
Interest accrued
100 
89 
Customer deposits
110 
107 
Mark-to-market derivative liabilities
75 
92 
Current regulatory liabilities
180 
100 
Other current liabilities
178 
168 
Current liabilities of discontinued operations
1,183 
1,166 
Total current liabilities
3,286 
2,660 
Long-term Debt, Net
5,274 
5,802 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
3,348 
3,166 
Accumulated deferred investment tax credits
67 
70 
Regulatory liabilities
1,666 
1,589 
Asset retirement obligations
385 
375 
Pension and other postretirement benefits
1,140 
1,138 
Other deferred credits and liabilities
585 
642 
Total deferred credits and other liabilities
7,191 
6,980 
Commitments and Contingencies
   
   
Stockholders' Equity:
 
 
Common Stock
2 
2 
Other paid-in capital
5,619 
5,616 
Retained earnings
762 
1,006 
Accumulated other comprehensive income (loss)
(9)
(8)
Stockholder's equity
6,374 
6,616 
Noncontrolling Interest
151 1
151 1
Total equity
6,525 
6,767 
TOTAL LIABILITIES AND EQUITY
22,276 
22,209 
Union Electric Company [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
19 
148 
Advances to money pool
   
24 
Accounts receivable - trade (less allowance for doubtful accounts)
229 
161 
Accounts receivable - affiliates
3 
4 
Unbilled revenue
225 
145 
Miscellaneous accounts and notes receivable
56 
48 
Materials and supplies
369 
397 
Current regulatory assets
132 
163 
Other current assets
100 
69 
Total current assets
1,133 
1,159 
Property and Plant, Net
10,264 
10,161 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
442 
408 
Intangible assets
18 
14 
Regulatory assets
830 
852 
Other assets
444 
449 
Total investments and other assets
1,734 
1,723 
TOTAL ASSETS
13,131 
13,043 
Current Liabilities:
 
 
Current maturities of long-term debt
309 
205 
Accounts and wages payable
198 
345 
Accounts payable - affiliates
103 
66 
Taxes accrued
107 
28 
Interest accrued
73 
60 
Current regulatory liabilities
71 
18 
Other current liabilities
90 
77 
Total current liabilities
951 
799 
Long-term Debt, Net
3,697 
3,801 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
2,474 
2,443 
Accumulated deferred investment tax credits
62 
64 
Regulatory liabilities
979 
917 
Asset retirement obligations
355 
346 
Pension and other postretirement benefits
465 
461 
Other deferred credits and liabilities
150 
158 
Total deferred credits and other liabilities
4,485 
4,389 
Commitments and Contingencies
   
   
Stockholders' Equity:
 
 
Common Stock
511 
511 
Other paid-in capital
1,556 
1,556 
Preferred stock not subject to mandatory redemption
80 
80 
Retained earnings
1,851 
1,907 
Stockholder's equity
3,998 
4,054 
TOTAL LIABILITIES AND EQUITY
13,131 
13,043 
Ameren Illinois Company [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
98 
   
Accounts receivable - trade (less allowance for doubtful accounts)
185 
182 
Accounts receivable - affiliates
13 
10 
Unbilled revenue
83 
146 
Miscellaneous accounts and notes receivable
18 
22 
Materials and supplies
141 
173 
Current regulatory assets
61 
84 
Current accumulated deferred income taxes, net
82 
85 
Other current assets
29 
47 
Total current assets
710 
749 
Property and Plant, Net
5,216 
5,052 
Investments and Other Assets:
 
 
Tax receivable - Genco
38 
39 
Goodwill
411 
411 
Regulatory assets
908 
934 
Other assets
83 
97 
Total investments and other assets
1,440 
1,481 
TOTAL ASSETS
7,366 
7,282 
Current Liabilities:
 
 
Current maturities of long-term debt
150 
150 
Borrowings from money pool
   
24 
Accounts and wages payable
184 
146 
Accounts payable - affiliates
91 
86 
Taxes accrued
13 
18 
Customer deposits
85 
85 
Mark-to-market derivative liabilities
55 
77 
Current environmental remediation
56 
37 
Current regulatory liabilities
110 
82 
Other current liabilities
79 
92 
Total current liabilities
823 
797 
Long-term Debt, Net
1,577 
1,577 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
1,082 
1,025 
Accumulated deferred investment tax credits
5 
5 
Regulatory liabilities
687 
672 
Pension and other postretirement benefits
416 
406 
Environmental remediation
196 
216 
Other deferred credits and liabilities
149 
183 
Total deferred credits and other liabilities
2,535 
2,507 
Commitments and Contingencies
   
   
Stockholders' Equity:
 
 
Common Stock
0 
0 
Other paid-in capital
1,965 
1,965 
Preferred stock not subject to mandatory redemption
62 
62 
Retained earnings
392 
360 
Accumulated other comprehensive income (loss)
12 
14 
Stockholder's equity
2,431 
2,401 
TOTAL LIABILITIES AND EQUITY
$ 7,366 
$ 7,282 
Consolidated Balance Sheet (Parenthetical) (USD $)
In Millions, except Per Share data, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Accounts receivable - trade allowance for doubtful accounts
$ 22 
$ 17 
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
400.0 
400.0 
Common stock, shares outstanding
242.6 
242.6 
Union Electric Company [Member]
 
 
Accounts receivable - trade allowance for doubtful accounts
6 
5 
Common stock, par value
$ 5 
$ 5 
Common stock, shares authorized
150.0 
150.0 
Common stock, shares outstanding
102.1 
102.1 
Ameren Illinois Company [Member]
 
 
Accounts receivable - trade allowance for doubtful accounts
$ 16 
$ 12 
Common stock, no par value
   
   
Common stock, shares authorized
45.0 
45.0 
Common stock, shares outstanding
25.5 
25.5 
Consolidated Statement of Cash Flows (USD $)
In Millions, unless otherwise specified
6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Cash Flows From Operating Activities:
 
 
Net income (loss)
$ (47)
$ (193)
Loss from discontinued operations, net of taxes
209 
394 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
334 
314 
Amortization of nuclear fuel
29 
41 
Amortization of debt issuance costs and premium/discounts
12 
8 
Deferred income taxes and investment tax credits, net
70 
110 
Allowance for equity funds used during construction
(16)1
(17)1
Stock-based compensation costs
14 
12 
Other
18 
(6)
Changes in assets and liabilities:
 
 
Receivables
(92)
(16)
Materials and supplies
77 
19 
Accounts and wages payable
(75)
(138)
Taxes accrued
67 
66 
Assets, other
49 
12 
Liabilities, other
9 
36 
Pension and other postretirement benefits
36 
23 
Counterparty collateral, net
35 
(1)
Net cash provided by operating activities - continuing operations
729 
664 
Net cash provided by operating activities - discontinued operations
39 
97 
Net cash provided by operating activities
768 
761 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(575)
(485)
Nuclear fuel expenditures
(25)
(52)
Purchases of securities - nuclear decommissioning trust fund
(97)
(206)
Sales and maturities of securities - nuclear decommissioning trust fund
89 
195 
Other
2 
(1)
Net cash used in investing activities - continuing operations
(606)
(549)
Net cash used in investing activities - discontinued operations
(31)
(64)
Net cash used in investing activities
(637)
(613)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(194)
(187)
Dividends paid to noncontrolling interest holders
(3)
(3)
Short-term debt, net
25 
(118)
Advances received for construction
7 
3 
Net cash used in financing activities - continuing operations
(165)
(305)
Net cash used in financing activities - discontinued operations
0 
0 
Net cash used in financing activities
(165)
(305)
Net change in cash and cash equivalents
(34)
(157)
Cash and cash equivalents at beginning of year
184 
248 
Cash and cash equivalents at end of period
150 
91 
Noncash financing activity - dividends on common stock
   
(7)
Union Electric Company [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income (loss)
126 
166 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
208 
201 
Amortization of nuclear fuel
29 
41 
Non cash Contested FAC
23 
0 
Amortization of debt issuance costs and premium/discounts
4 
3 
Deferred income taxes and investment tax credits, net
13 
76 
Allowance for equity funds used during construction
(14)
(15)
Changes in assets and liabilities:
 
 
Receivables
(155)
(65)
Materials and supplies
28 
(43)
Accounts and wages payable
(119)
(164)
Taxes accrued
79 
29 
Assets, other
61 
12 
Liabilities, other
37 
42 
Pension and other postretirement benefits
18 
18 
Net cash provided by operating activities
338 
301 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(273)
(299)
Nuclear fuel expenditures
(25)
(52)
Purchases of securities - nuclear decommissioning trust fund
(97)
(206)
Sales and maturities of securities - nuclear decommissioning trust fund
89 
195 
Money pool advances, net
24 
0 
Other
(3)
(5)
Net cash used in investing activities
(285)
(367)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(180)
(200)
Dividends on preferred stock
(2)
(2)
Money pool borrowings, net
0 
67 
Net cash used in financing activities
(182)
(135)
Net change in cash and cash equivalents
(129)
(201)
Cash and cash equivalents at beginning of year
148 
201 
Cash and cash equivalents at end of period
19 
0 
Ameren Illinois Company [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income (loss)
64 
61 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
121 
105 
Amortization of debt issuance costs and premium/discounts
7 
4 
Deferred income taxes and investment tax credits, net
61 
63 
Other
(4)
(5)
Changes in assets and liabilities:
 
 
Receivables
62 
62 
Materials and supplies
50 
59 
Accounts and wages payable
46 
13 
Taxes accrued
(6)
(1)
Assets, other
(4)
(3)
Liabilities, other
(18)
3 
Pension and other postretirement benefits
15 
(5)
Counterparty collateral, net
32 
4 
Net cash provided by operating activities
426 
360 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(283)
(184)
Money pool advances, net
0 
(67)
Other
4 
4 
Net cash used in investing activities
(279)
(247)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(30)
(75)
Dividends on preferred stock
(2)
(2)
Money pool borrowings, net
(24)
0 
Advances received for construction
7 
3 
Net cash used in financing activities
(49)
(74)
Net change in cash and cash equivalents
98 
39 
Cash and cash equivalents at beginning of year
   
21 
Cash and cash equivalents at end of period
$ 98 
$ 60 
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 expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.
•
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 Illinois Company, or Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
•
AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services.
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 is subject to FERC approval. Ameren has commenced a sale process for these three gas-fired energy centers and expects a third-party sale to be completed during 2013. See Note 2 - 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. 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 Ameren’s financial statements have been revised to exclude discontinued operations for all periods presented. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation.
The financial statements of Ameren are prepared on a consolidated basis. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.
During preparation of the 2012 annual statements of cash flows, it was identified that Ameren’s and Ameren Missouri’s 2012 interim statements of cash flows incorrectly classified certain activity from the nuclear decommissioning trust fund. Although not material, operating cash flows were overstated by $14 million, $26 million, and $49 million for the year-to-date periods ended March, 31, 2012, June 30, 2012, and September 30, 2012, respectively. The overstated operating cash flows resulted in the investing cash flows being understated by the same amounts. The cash flows for the six months ended June 30, 2012, for Ameren and Ameren Missouri have been revised in this report to correct for this error. The cash flows for the nine months ended September 30, 2012, will be revised to correct for this error in the Ameren and Ameren Missouri reports for the quarter ending September 30, 2013.
Earnings Per Share
There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three and six months ended June 30, 2013, and 2012. The number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.
Stock-based Compensation
A summary of nonvested performance share units at June 30, 2013, and changes during the six months ended June 30, 2013, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) are presented below:
 
Performance Share Units
 
Share Units
Weighted-average Fair Value Per Unit at Grant Date
Nonvested as of January 1, 2013
1,192,487

$
33.56

Granted(a)
834,919

31.19

Forfeitures
(7,757
)
32.66

Vested(b)
(129,226
)
31.27

Nonvested as of June 30, 2013
1,890,423

$
32.68

(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2013 under the 2006 Plan.
(b)
Share units vested due to the attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.
The fair value of each share unit awarded in 2013 under the 2006 Plan was determined to be $31.19. That amount was based on Ameren’s closing common share price of $30.72 at December 31, 2012, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total stockholder return for a three-year performance period relative to the designated peer group beginning January 1, 2013. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.36%, volatility of 12% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.
Intangible Assets
Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At June 30, 2013, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $18 million and $18 million, respectively, at June 30, 2013. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $14 million and $14 million, respectively, at December 31, 2012.
Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. In accordance with the MoPSC's 2012 electric rate order, the majority of Ameren Missouri's amortization of intangible assets is deferred as a regulatory asset pending future recovery from customers through rates. The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri, and Ameren Illinois, during the three and six months ended June 30, 2013, and 2012.
 
 
Three Months
 
Six Months
 
 
2013
 
2012
 
2013
 
2012
Ameren Missouri
$
—

$
(a)
$
(a)

$
(a)
Ameren Illinois
 
3

 
(a)
 
7

 
(a)
Ameren
$
3

$
(a)
$
7

$
(a)
(a)
Less than $1 million.
Excise Taxes
Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in “Taxes accrued” on the balance sheet. The following table presents excise taxes recorded in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” for the three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six Months
 
2013
 
2012
 
2013
 
2012
Ameren Missouri
$
38

 
$
38

 
$
71

 
$
65

Ameren Illinois
11

 
10

 
33

 
28

Ameren
$
49

 
$
48

 
$
104

 
$
93


Uncertain Tax Positions
The amount of unrecognized tax benefits as of June 30, 2013, was $193 million, $127 million, and $4 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2013, that would impact the effective tax rate, if recognized, was $49 million, less than $1 million, and $(1) million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits that would impact the effective tax rate, if recognized, for Ameren increased by $48 million as of June 30, 2013, all of which occurred during the first quarter of 2013. This increase is primarily due to uncertainty related to the historical computation of Ameren’s tax basis in its stock investment in AER.
Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2012 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 12 months for the years 2007 through 2010. This settlement, which is 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 $126 million, $110 million, and $5 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. 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 Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. 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.
Ameren Missouri has an uncertain tax position tracker. Under Missouri’s regulatory framework, uncertain income tax positions do not reduce Ameren Missouri’s electric rate base. When an uncertain income tax position liability is resolved, the MoPSC requires, through the uncertain tax position tracker, the creation of a regulatory asset or regulatory liability to reflect the time value (using the weighted-average cost of capital included in each of the electric rate orders in effect before the tax position was resolved) of the difference between the uncertain income tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will be amortized over three years beginning on the effective date of new rates established in the next electric rate case.
Asset Retirement Obligations
AROs at Ameren, Ameren Missouri, and Ameren Illinois increased compared to December 31, 2012, to reflect the accretion of obligations to their fair values.
Based on the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. Therefore, these AROs are classified as continuing operations. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
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 were classified as a component of equity separate from Ameren's equity on its consolidated balance sheet. A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three and six months ended June 30, 2013, and 2012, is shown below:
  
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
Ameren:
 
 
 
 
 
 
 
Noncontrolling interests, beginning of period (a)
$
151

 
$
147

 
$
151

 
$
149

Net income from continuing operations attributable to noncontrolling interests
1

 
1

 
3

 
3

Net income (loss) from discontinued operations attributable to noncontrolling interests
—

 
(2
)
 
—

 
(4
)
Dividends paid to noncontrolling interest holders
(1
)
 
(1
)
 
(3
)
 
(3
)
Noncontrolling interests, end of period (a)
$
151

 
$
145

 
$
151

 
$
145

(a)
Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations.” The 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s June 30, 2013, and December 31, 2012 balance sheets. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
Accounting and Reporting Developments
The following is a summary of recently adopted authoritative accounting guidance that could impact the Ameren Companies.
Presentation of Comprehensive Income
In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity.
In February 2013, 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. This guidance was effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI for the Ameren Companies related to pension and other postretirement plan activity. These amounts were immaterial during the first and second quarters of 2013, and therefore no additional disclosures were required.
Disclosures about Offsetting Assets and Liabilities
In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The Ameren Companies adopted this guidance for the first quarter of 2013. The implementation of this additional guidance did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. See Note 7 - Derivative Financial Instruments for the required additional disclosures.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued additional authoritative accounting guidance to provide explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. The amended guidance will not affect the Ameren Companies' results of operations, financial position, or liquidity, as this guidance is presentation-related only. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2014.
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 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. The obligations to be assumed by IPH are estimated at $37 million at June 30, 2013. IPH will also acquire the estimated $15 million asset at June 30, 2013, 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 June 30, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of June 30, 2013. 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 June 30, 2013, were $29 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 has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013.
Completion of the New AER sale to IPH is 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 July 26, 2013, FERC issued an order seeking additional information. In early August 2013, AER and Dynegy responded to FERC’s request for additional information. Several wholesale customers filed a protest with FERC regarding the application. 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 10 - 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 one-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 9 - Related Party Transactions 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. As a result, on March 14, 2013, Genco received an initial payment of $100 million in accordance with the terms of the amended put option agreement. Genco advanced the initial payment amount it received into the non-state-regulated subsidiary money pool. 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. Genco and Medina Valley have engaged three appraisers to conduct a fair market valuation of the Elgin, Gibson City, and Grand Tower gas-fired energy centers, which valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers. At the closing, Genco will receive an additional amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City, and Grand Tower gas-fired energy centers less the initial payment of $100 million, for a total purchase price of at least $133 million, and Genco will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City, and Grand Tower gas-fired energy centers as a condition to the transaction agreement. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013. Should FERC approval not be obtained and the transfer of the Elgin, Gibson City, and Grand Tower energy centers to Medina Valley cannot be completed, Genco will be required to return to Medina Valley the initial payment received in March 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.
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.
The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six months
 
 
2013
 
2012
 
2013
 
2012
 
Operating revenues
$
303

 
$
258

 
$
567

 
$
504

 
Operating expenses
(310
)

(238
)
 
(725
)
(a) 
(1,064
)
(b) 
Operating income (loss)
(7
)
 
20

 
(158
)
 
(560
)
 
Other income (loss)
1

 
—

 
(1
)
 
—

 
Interest charges
(11
)
 
(14
)
 
(22
)
 
(29
)
 
Income (loss) before income taxes
(17
)
 
6

 
(181
)
 
(589
)
 
Income tax (expense) benefit
7

 
42

 
(28
)
 
195

 
Income (loss) from discontinued operations, net of taxes
$
(10
)
 
$
48

 
$
(209
)
 
$
(394
)
 
(a)
Includes a noncash pretax impairment charge 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.
(b)
Includes a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value under held and used accounting guidance.
As the New AER disposal group continued to meet the discontinued operations criteria at June 30, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the terms of Ameren’s agreement to divest New AER to IPH. Ameren will receive no cash proceeds from IPH for the divestiture of New AER. Ameren recorded a pretax charge to earnings of $155 million for the three months ended March 31, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. The pretax charge to earnings increased by $13 million during the three months ended June 30, 2013, as the disposal group’s carrying value increased, primarily as a result of derivative market value gains. 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. The impairment loss was recorded in “Operating expenses” within the components of the discontinued operations statement of income (loss) with a corresponding reduction in “Property and Plant, net” within the components of the discontinued operations balance sheet. 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.
Ameren adjusted accumulated deferred income taxes on its balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, during the three months ended March 31, 2013, when it became apparent that the temporary difference would reverse. This change in basis resulted in a discontinued operations deferred tax expense of $98 million, which was partially offset by the expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge, during the three months ended March 31, 2013. During the second quarter of 2013, Ameren recorded tax benefits of $6 million related to the incremental pretax loss from discontinued operations recorded during the second quarter of 2013. In addition, Ameren recorded a $1 million reduction in discontinued operations deferred tax expense during the second quarter of 2013 to reflect the excess of tax basis over financial reporting basis of Ameren’s stock investment in AER. Ameren recorded a cumulative discontinued operations deferred tax expense of $97 million, which was partially offset by the expected tax benefits of $69 million related to the pretax loss from discontinued operations including the 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.
As the Elgin, Gibson City, and Grand Tower energy center disposal group continued to meet the discontinued operations criteria at June 30, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the appraised value of these three gas-fired energy centers. In December 2012, 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 three months ended March 31, 2013, with no adjustment necessary during the three 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 does not expect to have significant continuing involvement or material cash flows with the Elgin, Gibson City, and Grand Tower energy centers after their sale.
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.
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 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 carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at June 30, 2013, and December 31, 2012:
 
June 30, 2013
 
December 31, 2012
Current assets of discontinued operations
 
 
 
Cash and cash equivalents
$
25

 
$
25

Accounts receivable and unbilled revenue
102

 
102

Materials and supplies
119

 
134

Mark-to-market derivative assets
111

 
102

Property and plant, net
615

 
748

Accumulated deferred income taxes, net
380

 
373

Other assets
134

 
116

Total current assets of discontinued operations
$
1,486

 
$
1,600

Current liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
$
142

 
$
133

Mark-to-market derivative liabilities
70

 
63

Long-term debt, net
824

 
824

Asset retirement obligations
87

 
78

Pension and other postretirement benefits
37

 
40

Other liabilities
23

 
28

Total current liabilities of discontinued operations
$
1,183

 
$
1,166

Accumulated other comprehensive income(a)
$
8

 
$
19

Noncontrolling interest(b)
$
8

 
$
8

(a)
Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s June 30, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.
(b)
The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s June 30, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.
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 9 - Related Party Transactions for additional information regarding existing transactions between Ameren and New AER.
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 day period. The transitional services may be provided for six months after the closing and can be extended by IPH on a month-to-month basis for up to an additional six months.
See Note 10 - 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.
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 June 30, 2013:
  
Required
Ratio
Actual
Ratio
Interest coverage ratio- restricted payment (a)
≥1.75
1.60

Interest coverage ratio- additional indebtedness (b)
≥2.50
1.60

Debt-to-capital ratio- additional indebtedness (b)
≤60%
50
%
(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.
Rate And Regulatory Matters
RATE AND REGULATORY MATTERS
RATE AND REGULATORY MATTERS
Below is a summary of updates to significant regulatory proceedings and related lawsuits. See also Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. 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
FAC Prudence Reviews
Missouri law requires the MoPSC to perform prudence reviews of Ameren Missouri's FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 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 Missouri during the period from March 1, 2009, to September 30, 2009. Ameren Missouri completed its refund to customers in 2012 as directed by the April 2011 MoPSC order.
In May 2012, upon appeal by Ameren Missouri, the Cole County Circuit Court reversed the MoPSC's April 2011 order. In June 2012, the MoPSC and a group of large industrial customers filed an appeal of the Cole County Circuit Court's ruling to the Missouri Court of Appeals, Western District. In May 2013, the Missouri Court of Appeals upheld the MoPSC’s April 2011 order and reversed the Cole County Circuit Court’s May 2012 decision. Ameren Missouri determined that it would not appeal the Missouri Court of Appeals’ decision.
Ameren Missouri’s FAC calculation for the period from October 1, 2009, to May 31, 2011, excluded all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda’s load caused by a severe ice storm in January 2009, similar to the FAC calculation for the period from March 1, 2009, to September 30, 2009. As a result of the Missouri Court of Appeal’s May 2013 decision on the MoPSC’s April 2011 order, Ameren Missouri recorded a pretax charge to earnings of $23 million, including $1 million for interest, in the second quarter of 2013 for its estimated obligation to refund to Ameren Missouri’s electric customers the earnings associated with these sales previously recognized by Ameren Missouri for the period from October 1, 2009, to May 31, 2011. Ameren Missouri recorded the charge to “Operating Revenues - Electric” and the related interest to “Interest Charges” with a corresponding offset to “Current regulatory liabilities.” No similar revenues were excluded from FAC calculations after May 2011. On July 31, 2013, the MoPSC issued an order calculating the refund of these earnings to be $26 million, including $1 million of interest. Ameren Missouri is evaluating its options regarding seeking rehearing or appeal of the MoPSC’s order as it relates to the additional $3 million of refunds, as Ameren Missouri believes it has already refunded $3 million to customers through the FAC.
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. This case remains pending and we cannot predict its outcome.
The MoPSC’s FAC prudence review for the period from June 1, 2011, to September 30, 2012, was initiated on March 1, 2013. The MoPSC is expected to issue an order for this prudence review in 2013.
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. In January 2013, Ameren Missouri appealed the order with respect to the amount of property taxes included in the order to the Missouri Court of Appeals, Western District. In July 2013, Ameren Missouri withdrew its appeal related to the 2012 electric rate order. In February 2013, the MoOPC, MIEC and other parties 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. The appeals filed by MoOPC, MIEC and other parties were consolidated and are still pending. A decision is expected by the Missouri Court of Appeals, Western District, in 2013. Ameren Missouri cannot predict the ultimate outcome of this appeal, which could adversely impact its results of operations.
Illinois
IEIMA
Under the provisions of the IEIMA, Ameren Illinois’ electric delivery service rates effective in 2013 are subject to an annual revenue requirement reconciliation to its actual 2013 costs. The 2013 revenue requirement reconciliation will be filed with the ICC in 2014. The approved annual revenue requirement reconciliation adjustment will be reflected in customer rates beginning in January 2015. Throughout the year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement in effect for that year and its best estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual costs incurred. As of June 30, 2013, Ameren Illinois recorded a $33 million regulatory asset to reflect the year-to-date portion of its expected 2013 revenue requirement reconciliation adjustment. As of June 30, 2013 and December 31, 2012, Ameren Illinois recorded a regulatory liability of $57 million and $55 million, respectively, to reflect its expected 2012 revenue requirement reconciliation adjustment, with interest, which will be refunded to customers in 2014, pending ICC approval as discussed below.
In May 2013, Illinois enacted into law certain amendments to the IEIMA that modify its implementation. The law clarified that the IEIMA requires that the year-end rate base be used to calculate the revenue requirement reconciliation and that the interest applied to the revenue requirement reconciliation and return on equity collar adjustments be equal to a company’s weighted-average return calculated under the formula rate.
In September 2012, the ICC issued an order in Ameren Illinois’ initial filing under the IEIMA’s performance-based formula rate framework. 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. In December 2012, the ICC issued an order in Ameren Illinois’ update filing approving an Ameren Illinois electric delivery service revenue requirement of $765 million, based on 2011 recoverable costs and expected net plant additions for 2012. The delivery service rates became effective on January 1, 2013, and will remain effective through the end of 2013. These rates are subject to a reconciliation to actual 2013 costs, which will be filed with the ICC in 2014. 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. Many of the issues that were the subject of Ameren Illinois’ appeals of the September 2012 order and the December 2012 order were resolved with the enactment of the May 2013 amendments to the IEIMA referred to above; however, disputes regarding the treatment of deferred taxes and vacation obligations as well as the calculation of Ameren Illinois’ capital structure remain. If the appellate court rules in favor of Ameren Illinois’ positions on these disputed items, the electric delivery service revenue requirement included in the December 2012 order would have increased by $11 million. Ameren Illinois anticipates that any changes originating from these appeals would be applied prospectively through the IEIMA formula rate process.
In April 2013, Ameren Illinois filed its annual electric delivery service formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. In July 2013, the update filing was revised based on the enactment of the May 2013 amendments to the IEIMA referred to above. Pending ICC approval, the revised update filing, as filed by Ameren Illinois, will result in an aggregate $38 million decrease in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2014. The update filing includes a proposed refund to customers of the 2012 revenue requirement reconciliation of $56 million, which includes an estimate for interest through the end of 2014. Ameren Illinois’ balance sheet as of June 30, 2013, includes a $57 million regulatory liability relating to this 2012 revenue requirement reconciliation, which will continue to accrue interest through 2014 and is expected to increase to $63 million with interest accrued through 2014. In the update filing, the proposed refund is partially offset by an annual revenue requirement increase of $18 million primarily due to increased recoverable costs over 2011 levels. Ameren Illinois’ filing reflects an electric delivery service revenue requirement of $783 million, before consideration of the 2012 revenue requirement reconciliation refund. In July 2013, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing. The ICC staff recommended an aggregate $60 million decrease in Ameren Illinois’ electric delivery service revenue requirement. The calculation includes a refund to customers of the 2012 revenue requirement reconciliation of $68 million, which includes an estimate for interest through the end of 2014. However, this refund is partially offset by an annual revenue requirement increase of $8 million primarily due to increased recoverable costs over 2011 levels. The ICC staff’s filing reflects an electric delivery service revenue requirement of $772 million, before consideration of the 2012 revenue requirement reconciliation refund. An ICC decision with respect to the July 2013 revised update filing is expected in December 2013 and will establish rates for all of 2014. In December 2013, Ameren Illinois will record an adjustment to its regulatory liability for its 2012 revenue requirement reconciliation refund based on the ICC’s order.
2013 Natural Gas Delivery Service Rate Case
In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service. The current request, as revised in July 2013, seeks to increase annual revenues for natural gas delivery service by $50 million. The revised natural gas rate increase 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. Ameren Illinois is also seeking recovery of capital costs to enable residential customers the option to choose their natural gas commodity supplier, although that option currently does not exist for these customers.
In August 2013, the ICC staff responded to Ameren Illinois' revised request and recommended a net increase in revenues for natural gas delivery service of $24 million, based on an 8.8% return on equity, a capital structure composed of 50.4% common equity, and a rate base of $1.1 billion.
A decision by the ICC in this proceeding is required by December 2013. Ameren Illinois cannot predict the level of any natural gas delivery service rate changes the ICC may approve 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.
Natural Gas Consumer, Safety and Reliability Act
In July 2013, Illinois enacted a law called the Natural Gas Consumer, Safety and Reliability Act that enables Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provide additional ICC oversight of natural gas utility performance. Utilities that participate may implement rate surcharges for certain infrastructure investments made between rate cases. The legislation allows natural gas utilities the option to file, and requires the ICC to approve, a rate rider mechanism to provide for recovery of costs associated with certain categories of investment to improve the safety and reliability of the state’s natural gas infrastructure. The legislation also requires natural gas utilities that choose to participate in this regulatory framework to file annual plans with the ICC and report on progress in achieving performance improvements. The law is effective immediately. Ameren Illinois is currently evaluating when to participate in this regulatory framework.
ATXI Transmission Project
ATXI’s Illinois Rivers project is a MISO-approved project to build a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. In 2012, ATXI made a filing with the ICC requesting a certificate of public convenience and necessity, and project approval. In July 2013, Illinois administrative law judges issued a proposed order finding that the project is necessary to address transmission and reliability needs in an efficient and equitable manner and that the project will benefit the development of a competitive electricity market. The administrative law judges also agreed that ATXI is capable of constructing and managing the project as well as financing it. The administrative law judges recommended approval of seven of a total of nine portions of the route. For the remaining two portions, the administrative law judges concluded that a determination could not be made as to whether these are the least cost alternatives and identified concerns around the placement of certain substations. ATXI has filed a response to the administrative law judges’ proposed order in a subsequent filing with the ICC. An order from the ICC is expected in August 2013.
Federal
2011 Wholesale Distribution Rate Case
In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers. 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. The timing of a FERC decision is uncertain. Based on the administrative law judge's initial decision, Ameren and Ameren Illinois each has included on its balance sheet in “Current regulatory liabilities” an estimate of $11 million and $8 million as of June 30, 2013, and December 31, 2012, respectively, for the refund due to wholesale customers relating to billings for the period from March 2011 through June 2013.
Ameren Illinois Electric Transmission Rate Refund
In July 2012, FERC issued an order with respect to 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. Ameren Illinois submitted a refund report in November 2012 and concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund is warranted.
In June 2013, FERC issued an order that rejected Ameren Illinois’ November 2012 refund report and provided guidance as to the filing of a new refund report. In July 2013, Ameren Illinois filed a revised refund report based on the guidance provided in the June 2013 order, and also filed a request for rehearing of that order. Ameren Illinois’ July 2013 refund report again concluded that no refund was warranted. Ameren Illinois estimates the maximum pretax charge to earnings for this contingency would be between $10 million and $15 million, before interest charges. If Ameren Illinois were to determine that a refund to its electric transmission customers is probable, a charge to earnings would be recorded for the refund in the period in which that determination was made and the amount could be estimated.
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 first installment of DOE's small modular nuclear reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. In November 2012, the DOE awarded the first installment of investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that a second installment of investment funds would be awarded during 2013. Westinghouse continues to seek funds from the DOE’s first installment of investment funds.
Westinghouse submitted an application to the DOE in June 2013 for the second installment of investment funds. If Westinghouse is awarded DOE's small modular reactor investment funds in this second installment round of funding, Ameren Missouri may pursue 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 would not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it would 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. As of June 30, 2013, Ameren Missouri has capitalized investments for the development of a new nuclear energy center of $69 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal. As discussed above, the DOE investment funds could help support the completion of a COL application. If the DOE does not select Westinghouse's applications for 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 regarding the first installment of DOE investment funds.
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 is made.
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, drawings under committed bank credit agreements, or commercial paper issuances.
The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement were not utilized for borrowings during the six months ended June 30, 2013. As of June 30, 2013, based on letters of credit issued under the 2012 Credit Agreements, as well as commercial paper outstanding, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively, at June 30, 2013, was $2.06 billion.
Commercial Paper
At June 30, 2013, Ameren had $25 million of commercial paper outstanding. The average daily commercial paper balances outstanding during the six months ended June 30, 2013, and 2012, were $13 million and $72 million, respectively. The weighted-average interest rates during the six months ended June 30, 2013, and 2012, were 0.54% and 0.94%, respectively. The peak short-term commercial paper balances outstanding during the six months ended June 30, 2013, and 2012, were $78 million and $229 million, respectively. The peak interest rates during the six months ended June 30, 2013, and 2012, were 0.85% and 1.25%, respectively. Ameren Missouri and Ameren Illinois did not utilize their commercial paper programs during the six months ended June 30, 2013, and 2012.
Indebtedness Provisions and Other Covenants
The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants within the 2012 Credit Agreements. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for a detailed description of these provisions.
The 2012 Credit Agreements contain nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The 2012 Credit Agreements require each of Ameren, Ameren Missouri and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of June 30, 2013, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 52%, 48% and 42%, for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, under the 2012 Illinois Credit Agreement and by virtue of the cross-default provisions of the 2012 Missouri Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, 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 June 30, 2013, was 4.9 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. Ameren’s ratios, as discussed above, include both continuing and discontinued operations for the purposes of these calculations.
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 June 30, 2013.
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 (parent) and AERG may participate in the utility money pool only as lenders. 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 rates for borrowing under the utility money pool for the three and six months ended June 30, 2013, were 0.07% and 0.09%, respectively (2012 - 0.14% and 0.12%, respectively).
Non-state-regulated Subsidiaries
Ameren (parent), Ameren Services, AER, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the 2012 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. 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 2 - 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 rates for borrowing under the non-state-regulated subsidiary money pool for the three and six months ended June 30, 2013, were 0.29% and 0.26%, respectively (2012 - 0.64% and 0.70%, respectively).
See Note 9 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and six months ended June 30, 2013, and 2012.
Long-Term Debt And Equity Financings
LONG-TERM DEBT AND EQUITY FINANCINGS
LONG-TERM DEBT AND EQUITY FINANCINGS
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 June 30, 2013, at an assumed annual 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
 
4.4
$
3,633

 
≥2.5
 
110.9
$
2,118

Ameren Illinois
 
≥2.0
 
7.3
 
3,581

(d) 
≥1.5
 
2.7
 
203

(a)
Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b)
Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $485 million and $645 million at Ameren Missouri and Ameren Illinois, respectively.
(c)
Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.
(d)
Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.
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 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 June 30, 2013, 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 June 30, 2013, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.
Other Income and Expenses
OTHER INCOME AND EXPENSES
OTHER INCOME AND EXPENSES
The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income (loss) for the three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six Months
 
 
2013
 
2012
 
2013
 
2012
 
Ameren:(a)
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
8

 
$
8

 
$
16

  
$
17

 
Interest income on industrial development revenue bonds
7

 
7

 
14

  
14

 
Interest and dividend income
1

 
4

 
1

 
4

 
Other
—

 
—

 
—

  
1

 
Total miscellaneous income
$
16

 
$
19

 
$
31

  
$
36

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
1

 
$
3


$
5

 
$
15

(b) 
Other
4

 
4

 
8

  
7

 
Total miscellaneous expense
$
5

 
$
7

 
$
13

  
$
22

 
Ameren Missouri:
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
7

 
$
7

 
$
14

  
$
15

 
Interest income on industrial development revenue bonds
7

 
7

 
14

 
14

 
Interest and dividend income
—

 
4

 
—

 
4

 
Total miscellaneous income
$
14

 
$
18

 
$
28

  
$
33

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
1

 
$
3

 
$
3

  
$
5

 
Other
2

 
1

 
5

  
2

 
Total miscellaneous expense
$
3

 
$
4

 
$
8

  
$
7

 
Ameren Illinois:
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
1

 
$
1

 
$
2

  
$
2

 
Interest and dividend income
1

 
—

 
1

  
—

 
Other
—

 
1

 
—

  
1

 
Total miscellaneous income
$
2

 
$
2

 
$
3

  
$
3

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
—

 
$
—


$
3

 
$
10

(b) 
Other
1

 
2

 
1

  
3

 
Total miscellaneous expense
$
1

 
$
2

 
$
4

  
$
13

 
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Includes Ameren Illinois’ one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 election to participate in the formula ratemaking process.
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, power, and uranium. Such price fluctuations may cause the following:
•
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•
market values of coal, natural gas, and uranium inventories that differ from the cost of those commodities in inventory; and
•
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
The following table presents open gross commodity contract volumes by commodity type as of June 30, 2013, and December 31, 2012:
 
Quantity (in millions, except as indicated)
Commodity
Accrual & NPNS
Contracts(a)
 
Other
Derivatives(b)
 
Derivatives That Qualify
for Regulatory Deferral(c)
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Coal (in tons)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri & Ameren
85

 
96

 
(d)

 
(d)

 
(d)

 
(d)

Fuel oils (in gallons)(e)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri & Ameren
(d)

 
(d)

 
(d)

 
(d)

 
58

 
70

Natural gas (in mmbtu)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
—

 
4

 
—

 
—

 
30

 
19

Ameren Illinois
9

 
16

 
(d)

 
(d)

 
127

 
128

Ameren
9

 
20

 
—

 
—

 
157

 
147

Power (in megawatthours)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
3

 
3

 
1

 
2

 
7

 
9

Ameren Illinois
18

 
21

 
(d)

 
(d)

 
11

 
14

Ameren
21

 
24

 
1

 
2

 
18

 
23

Renewable energy credits(f)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
3

 
3

 
(d)

 
(d)

 
(d)

 
(d)

Ameren Illinois
11

 
12

 
(d)

 
(d)

 
(d)

 
(d)

Ameren
14

 
15

 
(d)

 
(d)

 
(d)

 
(d)

Uranium (pounds in thousands)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri & Ameren
4,671

 
5,142

 
(d)

 
(d)

 
514

 
446

(a)
Accrual contracts include commodity contracts that do not qualify as derivatives. As of June 30, 2013, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.
(b)
As of June 30, 2013, these contracts ran through December 2014 for power.
(c)
As of June 30, 2013, these contracts ran through October 2015, October 2019, May 2032, and May 2015 for fuel oils, natural gas, power, and uranium, respectively.
(d)
Not applicable.
(e)
Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.
(f)
A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power.
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 our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income (loss) or the statement of income and comprehensive income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income (loss) or the statement of income and comprehensive income.
Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and Ameren Illinois believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.
Certain derivative 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 statement of income (loss) or the statement of income and comprehensive income in the period in which the change occurs.
Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible commodity contracts.
The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2013, and December 31, 2012:
 
Balance Sheet Location
 
Ameren
 
Ameren Missouri
 
Ameren Illinois
2013
 
 
 
 
 
 
Derivative assets not designated as hedging instruments(a)
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
Fuel oils
Other current assets
$
5

$
5

$
—

 
Other assets
 
2

 
2

 
—

Natural gas
Other current assets
 
2

 
1

 
1

 
Other assets
 
1

 
—

 
1

Power
Other current assets
 
45

 
44

 
1

 
Other assets
 
2

 
1

 
1

 
Total assets
$
57

$
53

$
4

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

$
(b)

$
—

 
Other current liabilities
 
—

 
2

 
—

 
Other deferred credits and liabilities
 
2

 
2

 
—

Natural gas
MTM derivative liabilities
 
52

 
(b)

 
45

 
Other current liabilities
 
—

 
7

 
—

 
Other deferred credits and liabilities
 
33

 
5

 
28

Power
MTM derivative liabilities
 
18

 
(b)

 
10

 
Other current liabilities
 
—

 
8

 
—

 
Other deferred credits and liabilities
 
73

 
1

 
72

Uranium
MTM derivative liabilities
 
3

 
(b)

 
—

 
Other current liabilities
 
—

 
3

 
—

 
Total liabilities
$
183

$
28

$
155

2012
 
 
 
 
 
 
Derivative assets not designated as hedging instruments(a)
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
Fuel oils
Other current assets
$
8

$
8

$
—

 
Other assets
 
4

 
4

 
—

Natural gas
Other current assets
 
1

 
—

 
1

 
Other assets
 
1

 
1

 
—

Power
Other current assets
 
14

 
14

 
—

 
Other assets
 
1

 
1

 
—

 
Total assets
$
29

$
28

$
1

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

$
(b)

$
—

 
Other current liabilities
 
—

 
2

 
—

 
Other deferred credits and liabilities
 
2

 
2

 
—

Natural gas
MTM derivative liabilities
 
64

 
(b)

 
56

 
Other current liabilities
 
—

 
8

 
—

 
Other deferred credits and liabilities
 
45

 
7

 
38

Power
MTM derivative liabilities
 
25

 
(b)

 
21

 
Other current liabilities
 
—

 
4

 
—

 
Other deferred credits and liabilities
 
90

 
—

 
90

Uranium
MTM derivative liabilities
 
1

 
(b)

 
—

 
Other current liabilities
 
—

 
1

 
—

 
Other deferred credits and liabilities
 
1

 
1

 
—

 
Total liabilities
$
230

$
25

$
205

(a)
Includes derivatives subject to regulatory deferral.
(b)
Balance sheet line item not applicable to registrant.
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 June 30, 2013, and December 31, 2012:
 
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
2013
 
 
 
 
 
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
 
Fuel oils derivative contracts(a)
$
—

 
$
—

 
$
—

Natural gas derivative contracts(b)
(83
)
 
(12
)
 
(71
)
Power derivative contracts(c)
(43
)
 
37

 
(80
)
Uranium derivative contracts(d)
(3
)
 
(3
)
 
—

2012
 
 
 
 
 
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
 
Fuel oils derivative contracts(a)
$
4

 
$
4

 
$
—

Natural gas derivative contracts(b)
(107
)
 
(14
)
 
(93
)
Power derivative contracts(c)
(99
)
 
12

 
(111
)
Uranium derivative contracts(d)
(2
)
 
(2
)
 
—

(a)
Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through October 2015 as of June 30, 2013. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013.
(b)
Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2016 at Ameren Illinois as of June 30, 2013. Current gains deferred as regulatory liabilities include $2 million, $1 million, and $1 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $52 million, $7 million, and $45 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2013.
(c)
Represents net gains (losses) associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri as of June 30, 2013. Current gains deferred as regulatory liabilities include $44 million, $43 million, and $1 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $16 million, $6 million, and $10 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2013.
(d)
Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through May 2015 as of June 30, 2013. Current losses deferred as regulatory assets include $3 million and $3 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013.
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 a master trading and netting agreement level by counterparty.
Although Ameren had not previously elected to offset fair value amounts and collateral for derivative instruments executed with the same counterparty under the same master netting arrangement, authoritative accounting guidance, effective in the first quarter 2013, requires those amounts eligible to be offset to be presented both at the gross and net amounts. The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of June 30, 2013, and December 31, 2012:
 
 
 
 
Gross Amounts Not Offset in the Balance Sheet
 
 
 
 
Gross Amounts Recognized in the Balance Sheet
 
Derivative Instruments
 
Cash Collateral Received/Posted(a)
 
Net
Amount
2013
 
 
 
 
 
 
 
 
Commodity contracts eligible to be offset:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren
 
$
57

 
$
15

 
$
—

 
$
42

Ameren Missouri
 
53

 
13

 
—

 
40

Ameren Illinois
 
4

 
2

 
—

 
2

Liabilities:
 
 
 
 
 
 
 
 
Ameren
 
$
183

 
$
15

 
$
32

 
$
136

Ameren Missouri
 
28

 
13

 
6

 
9

Ameren Illinois
 
155

 
2

 
26

 
127

2012
 
 
 
 
 
 
 
 
Commodity contracts eligible to be offset:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren
 
$
29

 
$
10

 
$
—

 
$
19

Ameren Missouri
 
28

 
9

 
—

 
19

Ameren Illinois
 
1

 
1

 
—

 
—

Liabilities:
 
 
 
 
 
 
 
 
Ameren
 
$
230

 
$
10

 
$
65

 
$
155

Ameren Missouri
 
25

 
9

 
7

 
9

Ameren Illinois
 
205

 
1

 
58

 
146

(a)
Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.
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 the maximum exposure, as of June 30, 2013, and December 31, 2012, if counterparty groups were to fail completely to perform on contracts by grouping. 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. 
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Oil and Gas
Companies
 
Total
2013
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
3

 
$
5

 
$
16

 
$
5

  
$
—

 
$
29

Ameren Illinois
—

 
—

 
1

 
—

  
1

 
2

Ameren
$
3

 
$
5

 
$
17

 
$
5

  
$
1

 
$
31

2012
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
2

 
$
3

 
$
14

 
$
3

  
$
—

 
$
22

Ameren Illinois
—

 
—

 
1

 
—

  
—

 
1

Ameren
$
2

 
$
3

 
$
15

 
$
3

  
$
—

 
$
23

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 and other collateral held. The Ameren Companies held no cash from counterparties based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements as of June 30, 2013 and December 31, 2012. As of June 30, 2013, no other collateral used to reduce exposure was held by the Ameren Companies. As of December 31, 2012, other collateral used to reduce exposure consisted of letters of credit of $1 million held by Ameren and Ameren Missouri.

The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2013, and December 31, 2012:
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Oil and Gas
Companies
 
Total
2013
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
1

 
$
4

 
$
2

 
$
3

  
$
—

 
$
10

Ameren Illinois
—

 
—

 
—

 
—

  
—

 
—

Ameren
$
1

 
$
4

 
$
2

 
$
3

  
$
—

 
$
10

2012
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
1

 
$
1

 
$
10

 
$
3

  
$
—

 
$
15

Ameren Illinois
—

 
—

 
—

 
—

  
—

 
—

Ameren
$
1

 
$
1

 
$
10

 
$
3

  
$
—

 
$
15

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 June 30, 2013, and December 31, 2012, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on June 30, 2013, or December 31, 2012, respectively, and (2) those counterparties with rights to do so requested collateral:
 
Aggregate Fair Value of
Derivative Liabilities(a)
 
Cash
Collateral Posted
 
Potential Aggregate Amount of
Additional  Collateral Required(b)
2013
 
 
 
 
 
Ameren Missouri
$
76

 
$
1

 
$
45

Ameren Illinois
116

 
26

 
82

Ameren
$
192

 
$
27

 
$
127

2012
 
 
 
 
 
Ameren Missouri
$
78

 
$
3

 
$
71

Ameren Illinois
148

 
58

 
84

Ameren
$
226

 
$
61

 
$
155

(a)
Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b)
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the netting effects of such agreements.
Derivatives that Qualify for Regulatory Deferral
The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and six months ended June 30, 2013, and 2012:
 
 
 
Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets
 
 
 
Three Months
 
Six Months
 
 
 
2013
 
2012
 
2013
 
2012
Ameren
Fuel oils
 
$
(4
)
 
$
(19
)
 
$
(4
)
 
$
(14
)
 
Natural gas
 
(12
)
 
46

 
24

 
28

 
Power(a)
 
36

 
(1
)
 
56

 
(163
)
 
Uranium
 
(1
)
 
—

 
(1
)
 
—

 
Total
 
$
19

 
$
26

 
$
75

 
$
(149
)
Ameren Missouri
Fuel oils
 
$
(4
)
 
$
(19
)
 
$
(4
)
 
$
(14
)
 
Natural gas
 
(2
)
 
5

 
2

 
3

 
Power
 
35

 
4

 
25

 
3

 
Uranium
 
(1
)
 
—

 
(1
)
 
—

 
Total
 
$
28

 
$
(10
)
 
$
22

 
$
(8
)
Ameren Illinois
Natural gas
 
$
(10
)
 
$
41

 
$
22

 
$
25

 
Power
 
1

 
63

 
31

 
(81
)
 
Total
 
$
(9
)
 
$
104

 
$
53

 
$
(56
)
(a)
Amounts include intercompany eliminations.
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 is comprised of 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 comprised primarily of 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 derivative 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 fair value estimation process, an evaluation of all sources is performed to identify any anomalies or potential errors.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of June 30, 2013:
 
 
Fair Value
 
 
 
Weighted
 
 
Assets
Liabilities
Valuation Technique
Unobservable Input
Range
Average
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
7

$
(4
)
Option model
Volatilities(%)(b)
8 - 32
20
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 3
2
 
Natural gas
2

(1
)
Option model
Volatilities(%)(b)
1 - 31
24
 
 
 
 
 
Nodal basis($/mmbtu)(c)
(0.35) - (0.06)
(0.3)
 
 
 
 
Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.1) - 0
0
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 2
1
 
 
 
 
 
Ameren credit risk(%)(c)(d)
3
(f)
 
Power(e)
44

(87
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c)
25 - 49
32
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(767) - 1,790
252
 
 
 
 
 
Nodal basis($/MWh)(c)
(4) - (1)
(3)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 7
3
 
 
 
 
 
Ameren credit risk(%)(c)(d)
3
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
5 - 8
6
 
 
 
 
 
Escalation rate(%)(b)(g)
4 - 5
4
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
40 - 44
40
Ameren Missouri
Fuel oils
$
7

$
(4
)
Option model
Volatilities(%)(b)
8 - 32
20
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 3
2
 
Natural gas
—

(1
)
Option model
Volatilities(%)(b)
1 - 31
24
 
 
 
 
 
Nodal basis($/mmbtu)(c)
(0.35) - (0.06)
(0.3)
 
 
 
 
Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.1) - 0
(0.1)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 2
1
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
3
(f)
 
Power(e)
42

(5
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c)
25 - 49
38
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(767) - 1,790
252
 
 
 
 
 
Nodal basis($/MWh)(c)
(4) - (1)
(2)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 3
3
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
3
(f)
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
40 - 44
40
Ameren Illinois
Natural gas
$
2

$
—

Option model
Volatilities(%)(b)
1 - 31
27
 
 
 
 
 
Nodal basis($/mmbtu)(c)
(0.3) - (0.27)
(0.28)
 
 
 
 
Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.1) - 0
0
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.69 - 2
1
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
3
(f)
 
Power(e)
2

(82
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(b)
26 - 39
30
 
 
 
 
 
Nodal basis($/MWh)(b)
(4) - (1)
(3)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
7
(f)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
3
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
5 - 8
6
 
 
 
 
 
Escalation rate(%)(b)(g)
4 - 5
4
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(c)
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(d)
Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances.
(e)
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.
(f)
Not applicable.
(g)
Escalation rate applies to power prices 2026 and beyond.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012:
 
 
Fair Value
 
 
 
Weighted
 
 
Assets
Liabilities
Valuation Technique
Unobservable Input
Range
Average
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
8

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

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

(2
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
43 - 46
44
Ameren Missouri
Fuel oils
$
8

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

(3
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c)
24 - 56
36
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(281) - 1,851
178
 
 
 
 
 
Nodal basis($/MWh)(c)
(5) - (1)
(2)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
.22 - 1
1
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
2
(e)
 
Uranium
—

(2
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
43 - 46
44
Ameren Illinois
Power(f)
$
—

$
(111
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(b)
22 - 47
30
 
 
 
 
 
Nodal basis($/MWh)(b)
(5) - (1)
(3)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
5
(e)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 8
6
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(c)
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(d)
Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances.
(e)
Not applicable.
(f)
Power valuations utilize visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.
In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded no gains or losses in the first six months of 2013 or 2012 related to valuation adjustments for counterparty default risk. At June 30, 2013, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $3 million, less than $1 million, and $3 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. At December 31, 2012, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million, less than $1 million, and $7 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively.
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 June 30, 2013:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
—

 
$
—

 
$
7

 
$
7

 
Natural gas
 
—

 
1

 
2

 
3

 
Power
 
—

 
3

 
44

 
47

 
Total derivative assets - commodity contracts
 
$
—

 
$
4

 
$
53

 
$
57

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
294

 
—

 
—

 
294

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
40

 
—

 
40

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
91

 
—

 
91

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
297

 
$
143

 
$
—

 
$
440

 
Total Ameren
 
$
297

 
$
147

 
$
53

 
$
497

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
—

 
$
—

 
$
7

 
$
7

 
Natural gas
 
—

 
1

 
—

 
1

 
Power
 
—

 
3

 
42

 
45

 
Total derivative assets - commodity contracts
 
$
—

 
$
4

 
$
49

 
$
53

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
294

 
—

 
—

 
294

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
40

 
—

 
40

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
91

 
—

 
91

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
297

 
$
143

 
$
—

 
$
440

 
Total Ameren Missouri
 
$
297

 
$
147

 
$
49

 
$
493

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
—

 
$
2

 
$
2

 
Power
 
—

 
—

 
2

 
2

 
Total Ameren Illinois
 
$
—

 
$
—

 
$
4

 
$
4

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

 
$
—

 
$
4

 
$
4

 
Natural gas
 
5

 
79

 
1

 
85

 
Power
 
—

 
4

 
87

 
91

 
Uranium
 
—

 
—

 
3

 
3

 
Total Ameren
 
$
5

 
$
83

 
$
95

 
$
183

Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
—

 
$
—

 
$
4

 
$
4

 
Natural gas
 
5

 
6

 
1

 
12

 
Power
 
—

 
4

 
5

 
9

 
Uranium
 
—

 
—

 
3

 
3

 
Total Ameren Missouri
 
$
5

 
$
10

 
$
13

 
$
28

Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
73

 
$
—

 
$
73

 
Power
 
—

 
—

 
82

 
82

 
Total Ameren Illinois
 
$
—

 
$
73

 
$
82

 
$
155

(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, 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:
 
 
 
 
 
 
 
 
 
Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
4

 
$
—

 
$
8

 
$
12

 
Natural gas
 
—

 
2

 
—

 
2

 
Power
 
—

 
1

 
14

 
15

 
Total derivative assets - commodity contracts
 
$
4

 
$
3

 
$
22

 
$
29

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
264

 
—

 
—

 
264

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
47

 
—

 
47

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
81

 
—

 
81

 
Asset-backed securities
 
—

 
11

 
—

 
11

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
265

 
$
141

 
$
—

 
$
406

 
Total Ameren
 
$
269

 
$
144

 
$
22

 
$
435

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
4

 
$
—

 
$
8

 
$
12

 
Natural gas
 
—

 
1

 
—

 
1

 
Power
 
—

 
1

 
14

 
15

 
Total derivative assets - commodity contracts
 
$
4

 
$
2

 
$
22

 
$
28

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
264

 
—

 
—

 
264

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
47

 
—

 
47

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
81

 
—

 
81

 
Asset-backed securities
 
—

 
11

 
—

 
11

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
265

 
$
141

 
$
—

 
$
406

 
Total Ameren Missouri
 
$
269

 
$
143

 
$
22

 
$
434

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
1

 
$
—

 
$
1

 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total    
Liabilities:
 
 
 
 
 
 
 
 
 
Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
1

 
$
—

 
$
3

 
$
4

 
Natural gas
 
7

 
102

 
—

 
109

 
Power
 
—

 
1

 
114

 
115

 
Uranium
 
—

 
—

 
2

 
2

 
Total Ameren
 
$
8

 
$
103

 
$
119

 
$
230

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

 
$
—

 
$
3

 
$
4

 
Natural gas
 
7

 
8

 
—

 
15

 
Power
 
—

 
1

 
3

 
4

 
Uranium
 
—

 
—

 
2

 
2

 
Total Ameren Missouri
 
$
8

 
$
9

 
$
8

 
$
25

Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
94

 
$
—

 
$
94

 
Power
 
—

 
—

 
111

 
111

 
Total Ameren Illinois
 
$
—

 
$
94

 
$
111

 
$
205

(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Balance excludes $2 million of receivables, payables, and accrued income, net.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2013:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
5

$
(a)

$
5

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Ending balance at June 30, 2013
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
Natural gas:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
—

$
2

$
2

Realized and unrealized gains (losses):
 

 

 

Included in regulatory assets/liabilities
 
—

 
—

 
—

Total realized and unrealized gains (losses)
 
—

 
—

 
—

Purchases
 
(1
)
 
—

 
(1
)
Ending balance at June 30, 2013
$
(1
)
$
2

$
1

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
—

$
(1
)
Power:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
2

$
(81
)
$
(79
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
1

 
1

 
2

Total realized and unrealized gains (losses)
 
1

 
1

 
2

Purchases
 
40

 
—

 
40

Settlements
 
(9
)
 
—

 
(9
)
Transfers out of Level 3
 
3

 
—

 
3

Ending balance at June 30, 2013
$
37

$
(80
)
$
(43
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
3

$
(4
)
$
(1
)
Uranium:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
(2
)
$
(a)

$
(2
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Settlements
 
1

 
(a)

 
1

Ending balance at June 30, 2013
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
(a)
Not applicable.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2012:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at April 1, 2012
$
7

$
(a)

$
7

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(4
)
 
(a)

 
(4
)
Total realized and unrealized gains (losses)
 
(4
)
 
(a)

 
(4
)
Purchases
 
2

 
(a)

 
2

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(1
)
 
(a)

 
(1
)
Ending balance at June 30, 2012
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
(2
)
$
(a)

$
(2
)
Power(b):
 
 
 
 
 
 
Beginning balance at April 1, 2012
$
20

$
(284
)
$
(82
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(4
)
 
(1
)
 
(10
)
Total realized and unrealized gains (losses)
 
(4
)
 
(1
)
 
(10
)
Purchases
 
22

 
—

 
22

Settlements
 
(11
)
 
64

 
(10
)
Transfers out of Level 3
 
(1
)
 
—

 
(1
)
Ending balance at June 30, 2012
$
26

$
(221
)
$
(81
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
(1
)
$
(6
)
 $
5

Uranium:
 
 
 
 
 
 
Beginning balance at April 1, 2012
$
(1
)
 
(a)

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

 
(a)

 
—

Total realized and unrealized gains (losses)
 
—

 
(a)

 
—

Ending balance at June 30, 2012
$
(1
)
 
(a)

$
(1
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
—

 
(a)

$
—

(a)
Not applicable.
(b)
Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2013:
  
 
Net derivative commodity contracts
Six Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
5

$
(a)

$
5

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Purchases
 
1

 
(a)

 
1

Settlements
 
(1
)
 
(a)

 
(1
)
Ending balance at June 30, 2013
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
Natural gas:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
—

$
—

$
—

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

 
1

 
1

Total realized and unrealized gains (losses)
 
—

 
1

 
1

Purchases
 
(1
)
 
1

 
—

Ending balance at June 30, 2013
$
(1
)
$
2

$
1

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
—

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
11

$
(111
)
$
(100
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
6

 
15

 
21

Total realized and unrealized gains (losses)
 
6

 
15

 
21

Purchases
 
40

 
—

 
40

Settlements
 
(22
)
 
16

 
(6
)
Transfers into Level 3
 
(2
)
 
—

 
(2
)
Transfers out of Level 3
 
4

 
—

 
4

Ending balance at June 30, 2013
$
37

$
(80
)
$
(43
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
—

$
15

$
15

Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
(2
)
$
(a)

$
(2
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Settlements
 
1

 
(a)

 
1

Ending balance at June 30, 2013
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
(a)
Not applicable.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2012:
  
 
Net derivative commodity contracts
Six Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
3

$
(a)

$
3

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Purchases
 
2

 
(a)

 
2

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(1
)
 
(a)

 
(1
)
          Transfers into Level 3
 
2

 
(a)

 
2

Ending balance at June 30, 2012
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
(1
)
$
(a)

$
(1
)
Natural gas:
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
(14
)
$
(160
)
$
(174
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(26
)
 
(28
)
Total realized and unrealized gains (losses)
 
(2
)
 
(26
)
 
(28
)
Settlements
 
1

 
16

 
17

          Transfers out of Level 3
 
15

 
170

 
185

Ending balance at June 30, 2012
$
—

$
—

$
—

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
9

$
114

$
123

Power(b):
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
21

$
(140
)
$
81

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
9

 
(221
)
 
(168
)
Total realized and unrealized gains (losses)
 
9

 
(221
)
 
(168
)
Purchases
 
22

 
—

 
22

Settlements
 
(24
)
 
140

 
(14
)
Transfers out of Level 3
 
(2
)
 
—

 
(2
)
Ending balance at June 30, 2012
$
26

$
(221
)
$
(81
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
3

$
(195
)
(c) $
(179
)
Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
(1
)
$
(a)

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

 
(a)

 
—

Total realized and unrealized gains (losses)
 
—

 
(a)

 
—

Ending balance at June 30, 2012
$
(1
)
$
(a)

$
(1
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
—

$
(a)

$
—

(a)
Not applicable.
(b)
Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.
(c)
The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois’ swap contracts, which expire May 2032.
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 of 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 June 30, 2013, and the previous reporting periods ended March 31, 2013 and December 31, 2012. 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 three and six months ended June 30, 2013, and 2012, 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 three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
Ameren - derivative commodity contracts:
 
 
 
 
 
 
 
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
—

 
$
—

 
$
—

 
$
2

Transfers out of Level 3 / Transfers into Level 2 - Natural gas
—

 
—

 
—

 
185

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

 
—

 
(2
)
 
—

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

 
(1
)
 
4

 
(2
)
Net fair value of Level 3 transfers
$
3

 
$
(1
)
 
$
2

 
$
185

Ameren Missouri - derivative commodity contracts:
 
 
 
 
 
 
 
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
—

 
$
—

 
$
—

 
$
2

Transfers out of Level 3 / Transfers into Level 2 - Natural gas
—

 
—

 
—

 
15

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

 
—

 
(2
)
 
—

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

 
(1
)
 
4

 
(2
)
Net fair value of Level 3 transfers
$
3

 
$
(1
)
 
$
2

 
$
15

Ameren Illinois - derivative commodity contracts:
 
 
 
 
 
 
 
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
$
—

 
$
—

 
$
—

 
$
170


The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Ameren’s and Ameren Missouri’s carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the fair value hierarchy as they are valued based on similar market transactions. The Ameren Companies’ short-term borrowings 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 capital lease obligations and preferred stock at June 30, 2013, and December 31, 2012:
  
June 30, 2013
 
December 31, 2012
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Ameren:(a)(b)
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
6,158

 
$
6,864

 
$
6,157

 
$
7,110

Preferred stock
142

 
124

 
142

 
123

Ameren Missouri:
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
4,006

 
$
4,470

 
$
4,006

 
$
4,625

Preferred stock
80

 
75

 
80

 
73

Ameren Illinois:
 
 
 
 
 
 
 
Long-term debt (including current portion)
$
1,727

 
$
1,940

 
$
1,727

 
$
2,020

Preferred stock
62

 
49

 
62

 
49

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet.
Related Party Transactions
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS
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, asset transactions, guarantees, services received or rendered, and borrowings and lendings.
Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. For a discussion of our material related party agreements, see Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K.
Put Option Agreement and Guaranty
On March 28, 2012, Genco entered into a put option agreement with AERG, which gave Genco the option to sell to AERG all, but not less than all, of the Elgin, Gibson City, and Grand Tower gas-fired energy centers. The put option agreement required AERG to secure and maintain an Ameren guarantee of payment of contingent obligations under the agreement. Ameren provided such a guarantee on March 28, 2012.
On March 14, 2013, the put option agreement was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley. The guarantee provided by Ameren was also modified to replace references to AERG with references to Medina Valley. The guarantee will remain in effect until either Medina Valley 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 Medina Valley to Genco. On March 14, 2013, Genco exercised the option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
Collateral Postings
Under the terms of the Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri and Marketing Company, as winning suppliers in the RFP process, may be required to post collateral. As of December 31, 2012, and June 30, 2013, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.
Marketing Company Sale of Trade Receivables to Ameren Illinois
In accordance with the Illinois Public Utilities Act, beginning in June 2012, 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. Marketing Company sells and Ameren Illinois purchases 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 June 30, 2013, Ameren Illinois’ payable to Marketing Company for the purchase of trade receivables totaled $10 million. During the six months ended June 30, 2013, Ameren Illinois purchased $38 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 Ameren’s consolidated financial statements. After the New AER divestiture is complete, these transactions will no longer be eliminated in Ameren’s consolidated financial statements.
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 reflected 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 2 - Divestiture Transactions and Discontinued Operations.
At June 30, 2013, Ameren had a total of $230 million in guarantees outstanding, which included:
•
$166 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. As of June 30, 2013, this amount does not represent an incremental consolidated Ameren obligation; rather, it represents Ameren parental guarantees of subsidiary obligations to third parties, which may include affiliates, in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren's estimated exposure for obligations under transactions covered by these guarantees was $29 million at June 30, 2013, which represents the total amount Ameren (parent) could be required to fund based on June 30, 2013 market prices.
•
$33 million associated with the guarantee provided by Ameren for Medina Valley on March 14, 2013, relating to the amended put option agreement between Genco and Medina Valley. Genco exercised the put option in March 2013 and received an initial payment of $100 million. Genco advanced the initial payment amount it received into the non-state-regulated subsidiary money pool.
•
$25 million provided to a clearing broker acting as futures commission merchant for the clearing of certain power, natural gas, and fuels commodity transactions for AER.
•
$6 million related to requirements for asset transactions, leasing, Medina Valley transactions through MISO and other service agreements. At June 30, 2013, Ameren estimated it had no exposure to any of these guarantees.
Additionally, at June 30, 2013, Ameren had issued letters of credit totaling $14 million as credit support to certain subsidiaries.
Miscellaneous Support Services
Ameren Missouri and Ameren Illinois provide storm-related and miscellaneous support services to each other on an as- needed basis.  Ameren Illinois provided to Ameren Missouri $2 million in storm-related support services during the three and six months ended June 30 2013.  Ameren Missouri provided to Ameren Illinois $1 million in miscellaneous support services during the three and six months ended June 30, 2012.  These amounts are reflected in “Operating Revenues - Other” on the statement of income and comprehensive income.
Money Pools
See Note 4 - Short-term Debt and Liquidity for a discussion of affiliate borrowing arrangements.
The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three and six months ended June 30, 2013, and 2012. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 4 - Short-term Debt and Liquidity of this report.
  
  
 
  
 
Three Months
 
Six Months
Agreement
Income Statement
Line Item
 
  
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Missouri
 
Ameren
Illinois
Ameren Missouri power supply
Operating Revenues
 
2013
$
(b)

$
(a)
$
1
$
(a)

agreements with Ameren Illinois
 
 
2012
 
(b)

 
(a)

 
(b)
 
(a)

Ameren Missouri and Ameren Illinois
Operating Revenues
 
2013
 
5

 
(b)

 
11
 
(b)

rent and facility services
 
 
2012
 
5

 
(b)

 
9
 
(b)

Ameren Missouri and Genco gas
Operating Revenues
 
2013
 
(b)

 
(a)

 
(b)
 
(a)

transportation agreement
 
 
2012
 
(b)

 
(a)

 
(b)
 
(a)

Transmission services agreement
Operating Revenues
 
2013
 
(a)

 
7

 
(a)
 
13

with Marketing Company
 
 
2012
 
(a)

 
3

 
(a)
 
5

Total Operating Revenues
 
 
2013
$
5

$
7

$
12
$
13

 
 
 
2012
 
5

 
3

 
9
 
5

Ameren Illinois power supply
Purchased Power
 
2013
$
(a)

$
22

$
(a)
$
48

agreements with Marketing Company
 
 
2012
 
(a)

 
72

 
(a)
 
160

Ameren Illinois power supply
Purchased Power
 
2013
 
(a)

 
(b)

 
(a)
 
1

agreements with Ameren Missouri
 
 
2012
 
(a)

 
(b)

 
(a)
 
(b)

Total Purchased Power
 
 
2013
$
(a)

$
22

$
(a)
$
49

 
 
 
2012
 
(a)

 
72

 
(a)
 
160

Ameren Services support services
Other Operations and Maintenance
 
2013
$
28

$
24

$
60
$
48

agreement

 
2012
 
27

 
22

 
55
 
45

Insurance premiums(c)
Other Operations and Maintenance
 
2013
 
(b)

 
(a)

 
(b)
 
(a)

 

 
2012
 
(b)

 
(a)

 
(b)
 
(a)

Total Other Operations and
 
 
2013
$
28

$
24

$
60
$
48

Maintenance Expenses
 
 
2012
 
27

 
22

 
55
 
45

Money pool borrowings (advances)
Interest Charges
 
2013
$
__

$
(b)

$
(b)
$
(b)

 
 
 
2012
 
__

 
(b)

 
__
 
(b)

(a)
Not applicable.
(b)
Amount less than $1 million.
(c)
Represents insurance premiums paid to Missouri Energy Risk Assurance Company, an affiliate, for replacement power.
Commitments And Contingencies
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES
We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements in this report and in our Form 10-K, will not have a material adverse effect on our results of operations, financial position, or liquidity.
Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Divestiture Transactions and Discontinued Operations, Note 3 - Rate and Regulatory Matters, Note 9 - Related Party Transactions and Note 11 - Callaway Energy Center in this report.
Callaway Energy Center
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at June 30, 2013. 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
for Single Incidents
 
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) 
Missouri Energy Risk Assurance Company
$
64

(g) 
$
—

  
(a)
Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b)
Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $17.5 million per year.
(c)
Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $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)
First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-radiation events. Effective July 1, 2013, an additional non-radiation limit of $200 million in excess of the $1.5 billion was made available. This additional coverage is a shared limit with other generators purchasing this coverage and includes one free reinstatement. Effective August 1, 2013, $500 million in excess of the $2.25 billion property coverage and $1.7 billion non-radiation coverage was provided by European Mutual Association for Nuclear Insurance. Concurrently, the Nuclear Electric Insurance Ltd. property limit for nuclear events was reduced by $500 million.
(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 replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Effective April 1, 2013, non-radiation events are sub-limited to $327.6 million.
(g)
Provides replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 9 - Related Party Transactions for more information on this affiliate transaction.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment was recently announced and is effective September 10, 2013. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.
Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.’s policies, subject to an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.
If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity.
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. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K.
At June 30, 2013, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, and equipment and meter reading services, among other agreements, at Ameren, Ameren Missouri and Ameren Illinois were $7,190 million, $5,026 million, and $2,122 million, respectively.
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 generation, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, 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 environmental laws and regulations, including the Illinois MPS that applies to AER's coal-fired energy centers in Illinois, the EPA is developing regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri, and AER, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions from new energy centers; revised national ambient air quality standards for fine particulates, SO2, and NOx emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; 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 is expected to propose CO­2 limits for existing fossil fuel-fired electric generation units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia Circuit in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and increased operating costs over the next five to ten years for Ameren, Ameren Missouri and AER. 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 MATS as of June 30, 2013. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013 as the technology requirements ultimately to be selected in these final rules are not yet known. The estimates shown in the tables 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, new standards intended to achieve national ambient air quality standards, or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;
•
additional or new 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 limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units;
•
new technology;
•
changes in expected power prices;
•
variations in costs of material or labor; and
•
alternative compliance strategies or investment decisions.
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 construction of two scrubbers at the Newton energy center.
(b)
Assumes the Merchant Generation facilities are owned by Ameren.
The following sections describe the more significant environmental laws and rules that affect or could affect our operations.
Clean Air Act
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR requires 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. 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. In March 2013, the EPA and certain environmental groups filed an appeal of the Court of Appeals’ remand of CSAPR to the United States Supreme Court. The United States Supreme Court has agreed to consider the appeal and is expected to hear oral arguments and rule on the appeal during its next term, which begins in October 2013 and ends in June 2014. 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 in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016. Ameren Missouri's Labadie and Meramec energy centers requested and were granted extensions to April 2016 to comply with the MATS.
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 rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren Missouri and AER are currently evaluating the new standard while the states of Missouri and Illinois develop their attainment plans.
In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone. The EPA is required to revisit these standards 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, Ameren Missouri and AER continue to assess the impacts of these new standards.
In July 2013, the EPA issued a final rule designating portions of the United States, including parts of Illinois and Missouri, as nonattainment for the national ambient air quality standard for SO2. The effected states must develop plans in the next 18 months to reduce emissions so that they can achieve the ambient air quality standards within five years. Ameren, Ameren Missouri and AER are assessing the impact of this designation.
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 greater volumes of lower-sulfur-content coal than Ameren Missouri's energy centers had 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, mercury control technology, and precipitator upgrades at multiple energy centers within its coal-fired fleet 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, or Ameren’s ability after the divestiture of New AER occurs, to make the Meredosia energy center available for any parties that may be interested in repowering one of its units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage.
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 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of AER.
Under the MPS, AER is required to reduce mercury, NOx and SO2 emissions with declining limits that started in 2009 for mercury and in 2010 for NOx and SO2. The final NOx limit became effective in 2012. The final mercury limit will become effective in 2015 and the final SO2 limit will become effective 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, AER is installing equipment designed to reduce its emissions of mercury, NOx, and SO2. AER has installed three scrubbers at two energy centers. Two additional scrubbers are being constructed at the 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 and Ameren Missouri expect to have adequate allowances for 2013 to avoid needing to make external purchases to comply with these programs.
Greenhouse Gas Regulation
State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions. Potential impacts from any such 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 law that restricts emissions of CO2 or requires energy centers to purchase allowances for CO2 emissions 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, greenhouse gas 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, economy wide 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 to address 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. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding 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 energy centers and therefore does not affect any of the Ameren, Ameren Missouri or AER 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 to be issued in 2013.
In June 2013, the Obama Administration announced that the EPA has been directed to set carbon emissions standards for both new and existing power plants. The EPA is expected to propose revised carbon regulations for new generating units by September 2013. In addition, the EPA has been directed to propose a carbon standard for existing power plants by June 2014 and to finalize such standard by June 2015. Currently, the Ameren Companies are unable to predict the outcome or impacts of such future regulations.
Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address alleged damages resulting from greenhouse gas emissions. 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. In May 2013, the dismissal of the lawsuit was affirmed by the United States Court of Appeals for the Fifth Circuit.
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. These 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. To the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. As a result, mandatory limits on the emission of greenhouse gases could have a material adverse impact on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity.
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 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. Ameren believes its defenses to the allegations at Genco described in the Notice of Violation are meritorious, and a recent court decision by the United States Court of Appeals for the Seventh Circuit recently held that similar claims older than five years were barred by the statute of limitations. If not reversed or overturned this decision may provide an additional defense to the allegations in the Newton energy center Notice of Violation. 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 in 2001, 2003, 2007, and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the 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 the requirement to install pollution control equipment, remain. Litigation of this matter could take years, and no trial date has been established. 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 and Ameren Missouri. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred.
Clean Water Act
In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25% 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 November 2013, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle energy centers at Ameren, Ameren Missouri and AER with cooling water systems are subject to this proposed rule. The 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 April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers), fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning, and gasification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments. The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If enacted as proposed, Ameren Missouri and AER would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations if enacted as proposed. The EPA expects to finalize the rule in 2014.
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 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER.
As of June 30, 2013, 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 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 June 30, 2013, Ameren Missouri has one remaining former MGP site for which remediation is scheduled. Remediation is complete at the other Ameren Missouri former MGP sites. Ameren Missouri does not currently have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with MGP sites.

The following table presents, as of June 30, 2013, the estimated obligation to complete the remediation of these former MGP sites.
  
Estimate
 
Recorded
  Liability(a)
  
Low
 
High
 
Ameren
$
256

 
$
339

 
$
256

Ameren Missouri
5

 
6

 
5

Ameren Illinois
251

 
333

 
251

(a)
Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was a better estimate.
The scope and extent to which these former MGP sites are remediated may increase as remediation efforts continue. Considerable uncertainty remains in these estimates as many factors can influence the ultimate actual costs, including site specific unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs may vary substantially from these estimates.
Ameren Illinois utilized an off-site landfill, which Ameren Illinois did not own, in connection with its operation of the Coffeen energy center prior to the formation of Genco. While not currently mandated, Ameren Illinois may be required to perform certain remediation activities associated with that landfill. As of June 30, 2013, Ameren Illinois estimated the obligation related to the cleanup at $0.5 million to $6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2013, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.
Ameren Missouri has responsibility for the 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 June 30, 2013, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the investigation and cleanup of this site, which was completed in 2005. Ameren Missouri anticipates that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup, and it therefore has no recorded liability at June 30, 2013, for this site.
Ameren Missouri also has a federal agency mandate to complete an investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri joined with other 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 approved the proposed site remedies, it will 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 Sauget Area 2. As of June 30, 2013, Ameren Missouri estimated its obligation related to Sauget Area 2 at $0.3 million to $10 million. Ameren Missouri recorded a liability of $0.3 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.
In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri owned substation in St. Charles, Missouri. As of June 30, 2013, Ameren Missouri estimated the obligation related to the cleanup at $1.7 million to $4.5 million. Ameren Missouri recorded a liability of $1.7 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. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules proposed in May 2010. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and AER are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and AER 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.
The Illinois EPA has issued violation notices with respect to groundwater conditions existing at Genco’s ash pond systems. AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds. The Illinois EPA is in the process of developing its own ash pond impoundment rulemaking and anticipates filing proposed rules with the Illinois Pollution Control Board in 2013. The rulemaking process could take up to two years to complete. During the first quarter of 2013, Genco and AERG revised their ARO fair value estimates relating to their ash ponds to reflect expected retirements dates. See Note 1 - Summary of Significant Accounting Policies for additional information related to our asset retirement obligations.
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 June 30, 2013, Ameren Missouri had an insurance receivable balance of $68 million. Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if its remaining liability insurance claims are not paid by insurers.
In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In January 2011, the district court ruled that the parties must first pursue alternative dispute resolution 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, which is pending in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. The insurance company filed a motion to compel arbitration, which the district court denied. In April 2013, the United States Court of Appeals for the Eighth Circuit affirmed the district court’s denial of the insurer’s motion and remanded the case to the district court.
Asbestos-related Litigation
Ameren, Ameren Missouri and Ameren Illinois have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies with the average number of parties being 80 as of June 30, 2013. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.
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 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren's divestiture of AER.
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of June 30, 2013:
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Total(a)
2
 
58
 
68
 
90
(a)
Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
At June 30, 2013, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $16 million, $7 million, and $9 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims.
Ameren Illinois has a tariff rider to recover the costs of IP asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At June 30, 2013, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. The rider will permit recovery 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 2,400 accounts primarily in annexed areas for the period 2004 through 2012.  In July 2013, the O’Fallon city administrator issued an order stating that Ameren Illinois was liable to the City of O’Fallon for $4 million. Ameren Illinois believes its defenses to the allegations are meritorious and will defend itself vigorously. In August 2013, Ameren Illinois filed an appeal and a stay of the O’Fallon city administrator’s order to the St. Clair County Circuit Court. As of June 30, 2013, Ameren Illinois estimated its obligation at $0.5 million to $4 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation to the City of O'Fallon, as no other amount within the range was a better estimate. 
In addition, at the end of 2012, six other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain accounts. At this time, it is premature in Ameren Illinois' review of the additional notices received at the end of 2012 to reasonably estimate any likelihood of loss.
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. During the 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. This charge was recorded within “Loss from Discontinued Operations, Net of Taxes” on Ameren’s consolidated statement of income (loss) in the second quarter of 2013.
Medina Valley Asset Sale
In February 2012, Ameren completed the sale of the Medina Valley energy center’s net property and plant for cash proceeds of $16 million and an additional $1 million to be paid at the two-year anniversary date of the sale if all terms of the sale agreement were met. Ameren recognized a $10 million pretax gain from this sale. In October 2012, the buyer of the Medina Valley energy center asserted that AER had not met all the terms of the sale agreement. During the first quarter of 2013, Ameren concluded it was no longer probable it would receive the additional $1 million associated with this sale and therefore expensed the receivable amount.
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 Missouri and other companies that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these companies 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 companies have entered into standard contracts with the DOE, which is the agency responsible for implementing 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.
Both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, however, no federal storage facility currently exists. 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 companies’ 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 to begin operation by 2048. 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 the DOE's failure to begin to dispose of the spent nuclear fuel from nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have 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 an annual reimbursement of Ameren Missouri’s spent fuel storage and related costs through at least 2013. In March 2013, Ameren Missouri submitted its 2012 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2012 cost reimbursement of $6 million during the third quarter of 2013. These costs were recorded in “Miscellaneous accounts and notes receivable” on Ameren’s and Ameren Missouri’s balance sheets.
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 energy center 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 new waste confidence final environmental impact statement (EIS) and a final rule to address the court's ruling. The newly created Waste Confidence Directorate within NRC now oversees the drafting of a new waste confidence EIS and rule, and its schedule presently provides for issuance of the final EIS and final rule by no later than September 2014. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility by 2016.
Electric utility rates charged to customers provide for the recovery of the Callaway energy center's decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the nuclear center, ending with the expiration of the energy center's current operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 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. 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 of the next triennial cost study and funding analysis is approved by the MoPSC. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center's decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's and Ameren Missouri's balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability.
See Note 3 - Rate and Regulatory Matters for additional information related to the Callaway energy center.
Retirement Benefits
RETIREMENT BENEFITS
RETIREMENT BENEFITS
Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to meet federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at June 30, 2013, the plan’s estimated investment performance through June 30, 2013, and Ameren’s 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 $500 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the voluntary employee’s beneficiary association trusts to match the annual postretirement expense.
The following table presents the components of the net periodic benefit cost for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 2013, and 2012:
  
Pension Benefits (a)
 
Postretirement Benefits (a)
 
Three Months
 
Six Months
 
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Service cost
$
22

 
$
20

 
$
46

 
$
41

 
$
5

 
$
5

 
$
11

 
$
11

Interest cost
41

 
41

 
81

 
83

 
11

 
11

 
23

 
24

Expected return on plan assets
(54
)
 
(52
)
 
(108
)
 
(104
)
 
(15
)
 
(14
)
 
(31
)
 
(28
)
Amortization of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
(1
)
 
(1
)
 
(2
)
 
(2
)
 
(1
)
 
(1
)
 
(2
)
 
(2
)
Actuarial loss
24

 
18

 
46

 
37

 
2

 
(1
)
 
4

 
2

Net periodic benefit cost
$
32

 
$
26

 
$
63

 
$
55

 
$
2

 
$
—

 
$
5

 
$
7

(a)
Excludes the EEI plans as they are included in discontinued operations.
Ameren Missouri and Ameren Illinois are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and six months ended June 30, 2013, and 2012:
  
Pension Costs
 
Postretirement Costs
 
Three Months
 
Six Months
 
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Ameren Missouri
$
18

 
$
16

 
$
36

 
$
32

 
$
2

 
$
—

 
$
5

 
$
5

Ameren Illinois
11

 
8

 
21

 
18

 
(1
)
 
—

 
—

 
2

Other
3

 
2

 
6

 
5

 
1

 
—

 
—

 
—

Ameren(a)
$
32

 
$
26

 
$
63

 
$
55

 
$
2

 
$
—

 
$
5

 
$
7

(a)
Includes amounts for Ameren registrants and nonregistrant subsidiaries, but excludes the EEI plans as they are included in discontinued operations.
Segment Information
SEGMENT INFORMATION
SEGMENT INFORMATION
Ameren historically had three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all the operations of Ameren Missouri’s business as described in Note 1 - Summary of Significant Accounting Policies. The Ameren Illinois segment for both Ameren and Ameren Illinois 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 2 - 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 2 - 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 revenues and specified items included in net income attributable to Ameren Corporation from continuing operations for the three and six months ended June 30, 2013, and 2012, and total assets as of June 30, 2013, and December 31, 2012.
Three Months
Ameren
Missouri
 
Ameren
Illinois
 
Other
 
Intersegment
Eliminations
 
Consolidated
 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
883

 
$
514

 
$
6

 
$
—

 
$
1,403

 
Intersegment revenues
6

 
2

 
—

 
(8
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
84

 
31

 
(10
)
 
—

 
105

 
2012
 
 
 
 
 
 
 
 
 
 
External revenues
$
838

 
$
564

 
$
—

 
$
—

 
$
1,402

 
Intersegment revenues
6

 
—

 
1

 
(7
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
143

 
32

 
(14
)

—

 
161

 
Six Months
  
 
  
 
  
 
  
 
  
 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,672

 
$
1,197

 
$
9

  
$
—

 
$
2,878

 
Intersegment revenues
13

 
3

 
1

  
(17
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
124

 
62

 
(27
)
  
—

 
159

 
2012
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,524

 
$
1,288

 
$
2

  
$
—

 
$
2,814

 
Intersegment revenues
11

 
—

 
2

  
(13
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
164

 
59

 
(25
)
 
—

 
198

 
As of June 30, 2013:
 
 
 
 
 
 
 
 
 
 
Total assets
$
13,131

 
$
7,366

 
$
1,354

 
$
(1,061
)
 
$
20,790

(a) 
As of December 31, 2012:
 
 
 
 
 
 
 
 
 
 
Total assets
$
13,043

 
$
7,282

 
$
1,228

 
$
(944
)
 
$
20,609

(a) 
(a)    Excludes “Current assets of discontinued operations.” See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
Summary Of Significant Accounting Policies (Policies)
Consolidation 
The financial statements of Ameren are prepared on a consolidated basis. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.
Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.
Earnings Per Share 
There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three and six months ended June 30, 2013, and 2012. The number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.
Intangible Assets 
Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At June 30, 2013, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $18 million and $18 million, respectively, at June 30, 2013. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $14 million and $14 million, respectively, at December 31, 2012.
Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. In accordance with the MoPSC's 2012 electric rate order, the majority of Ameren Missouri's amortization of intangible assets is deferred as a regulatory asset pending future recovery from customers through rates.
Excise Taxes 
Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in “Taxes accrued” on the balance sheet.
Uncertain Tax Positions 
The amount of unrecognized tax benefits as of June 30, 2013, was $193 million, $127 million, and $4 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2013, that would impact the effective tax rate, if recognized, was $49 million, less than $1 million, and $(1) million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits that would impact the effective tax rate, if recognized, for Ameren increased by $48 million as of June 30, 2013, all of which occurred during the first quarter of 2013. This increase is primarily due to uncertainty related to the historical computation of Ameren’s tax basis in its stock investment in AER.
Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2012 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 12 months for the years 2007 through 2010. This settlement, which is 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 $126 million, $110 million, and $5 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. 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 Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. 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.
Ameren Missouri has an uncertain tax position tracker. Under Missouri’s regulatory framework, uncertain income tax positions do not reduce Ameren Missouri’s electric rate base. When an uncertain income tax position liability is resolved, the MoPSC requires, through the uncertain tax position tracker, the creation of a regulatory asset or regulatory liability to reflect the time value (using the weighted-average cost of capital included in each of the electric rate orders in effect before the tax position was resolved) of the difference between the uncertain income tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will be amortized over three years beginning on the effective date of new rates established in the next electric rate case.
Asset Retirement Obligations 
Based on the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. Therefore, these AROs are classified as continuing operations. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
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 were classified as a component of equity separate from Ameren's equity on its consolidated balance sheet.
Accounting and Reporting Developments 
The following is a summary of recently adopted authoritative accounting guidance that could impact the Ameren Companies.
Presentation of Comprehensive Income
In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity.
In February 2013, 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. This guidance was effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI for the Ameren Companies related to pension and other postretirement plan activity. These amounts were immaterial during the first and second quarters of 2013, and therefore no additional disclosures were required.
Disclosures about Offsetting Assets and Liabilities
In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The Ameren Companies adopted this guidance for the first quarter of 2013. The implementation of this additional guidance did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. See Note 7 - Derivative Financial Instruments for the required additional disclosures.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued additional authoritative accounting guidance to provide explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. The amended guidance will not affect the Ameren Companies' results of operations, financial position, or liquidity, as this guidance is presentation-related only. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2014.
Derivative Financial Instruments Derivative Financial Instruments (Policies)
Derivatives
We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, power, and uranium. Such price fluctuations may cause the following:
•
an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•
market values of coal, natural gas, and uranium inventories that differ from the cost of those commodities in inventory; and
•
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
Retirement Benefits Retirement Benefits (Policies)
Retirement Benefits
Ameren’s pension and postretirement plans are funded in compliance with income tax regulations and to meet federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Considering Ameren’s assumptions at June 30, 2013, the plan’s estimated investment performance through June 30, 2013, and Ameren’s 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 $500 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the voluntary employee’s beneficiary association trusts to match the annual postretirement expense.
Summary Of Significant Accounting Policies (Tables)
Summary Of Nonvested Shares Related To Long-Term Incentive Plan 
A summary of nonvested performance share units at June 30, 2013, and changes during the six months ended June 30, 2013, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) are presented below:
 
Performance Share Units
 
Share Units
Weighted-average Fair Value Per Unit at Grant Date
Nonvested as of January 1, 2013
1,192,487

$
33.56

Granted(a)
834,919

31.19

Forfeitures
(7,757
)
32.66

Vested(b)
(129,226
)
31.27

Nonvested as of June 30, 2013
1,890,423

$
32.68

(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2013 under the 2006 Plan.
(b)
Share units vested due to the attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.
Schedule Of Amortization Expense Based On Usage Of Renewable Energy Credits And Emission Allowances 
The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri, and Ameren Illinois, during the three and six months ended June 30, 2013, and 2012.
 
 
Three Months
 
Six Months
 
 
2013
 
2012
 
2013
 
2012
Ameren Missouri
$
—

$
(a)
$
(a)

$
(a)
Ameren Illinois
 
3

 
(a)
 
7

 
(a)
Ameren
$
3

$
(a)
$
7

$
(a)
(a)
Less than $1 million.
Schedule of Excise Taxes 
The following table presents excise taxes recorded in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” for the three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six Months
 
2013
 
2012
 
2013
 
2012
Ameren Missouri
$
38

 
$
38

 
$
71

 
$
65

Ameren Illinois
11

 
10

 
33

 
28

Ameren
$
49

 
$
48

 
$
104

 
$
93

Equity Changes Attributable To Noncontrolling Interest 
A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three and six months ended June 30, 2013, and 2012, is shown below:
  
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
Ameren:
 
 
 
 
 
 
 
Noncontrolling interests, beginning of period (a)
$
151

 
$
147

 
$
151

 
$
149

Net income from continuing operations attributable to noncontrolling interests
1

 
1

 
3

 
3

Net income (loss) from discontinued operations attributable to noncontrolling interests
—

 
(2
)
 
—

 
(4
)
Dividends paid to noncontrolling interest holders
(1
)
 
(1
)
 
(3
)
 
(3
)
Noncontrolling interests, end of period (a)
$
151

 
$
145

 
$
151

 
$
145

(a)
Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations.” The 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s June 30, 2013, and December 31, 2012 balance sheets. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
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 June 30, 2013, and December 31, 2012:
 
June 30, 2013
 
December 31, 2012
Current assets of discontinued operations
 
 
 
Cash and cash equivalents
$
25

 
$
25

Accounts receivable and unbilled revenue
102

 
102

Materials and supplies
119

 
134

Mark-to-market derivative assets
111

 
102

Property and plant, net
615

 
748

Accumulated deferred income taxes, net
380

 
373

Other assets
134

 
116

Total current assets of discontinued operations
$
1,486

 
$
1,600

Current liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
$
142

 
$
133

Mark-to-market derivative liabilities
70

 
63

Long-term debt, net
824

 
824

Asset retirement obligations
87

 
78

Pension and other postretirement benefits
37

 
40

Other liabilities
23

 
28

Total current liabilities of discontinued operations
$
1,183

 
$
1,166

Accumulated other comprehensive income(a)
$
8

 
$
19

Noncontrolling interest(b)
$
8

 
$
8

(a)
Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s June 30, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture.
(b)
The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s June 30, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture.
The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six months
 
 
2013
 
2012
 
2013
 
2012
 
Operating revenues
$
303

 
$
258

 
$
567

 
$
504

 
Operating expenses
(310
)

(238
)
 
(725
)
(a) 
(1,064
)
(b) 
Operating income (loss)
(7
)
 
20

 
(158
)
 
(560
)
 
Other income (loss)
1

 
—

 
(1
)
 
—

 
Interest charges
(11
)
 
(14
)
 
(22
)
 
(29
)
 
Income (loss) before income taxes
(17
)
 
6

 
(181
)
 
(589
)
 
Income tax (expense) benefit
7

 
42

 
(28
)
 
195

 
Income (loss) from discontinued operations, net of taxes
$
(10
)
 
$
48

 
$
(209
)
 
$
(394
)
 
(a)
Includes a noncash pretax impairment charge 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.
(b)
Includes a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value under held and used accounting guidance.
Schedule Of Coverage Ratios 
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 June 30, 2013, at an assumed annual 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
 
4.4
$
3,633

 
≥2.5
 
110.9
$
2,118

Ameren Illinois
 
≥2.0
 
7.3
 
3,581

(d) 
≥1.5
 
2.7
 
203

(a)
Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b)
Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $485 million and $645 million at Ameren Missouri and Ameren Illinois, respectively.
(c)
Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.
(d)
Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.
Schedule Of Coverage Ratios 
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 June 30, 2013:
  
Required
Ratio
Actual
Ratio
Interest coverage ratio- restricted payment (a)
≥1.75
1.60

Interest coverage ratio- additional indebtedness (b)
≥2.50
1.60

Debt-to-capital ratio- additional indebtedness (b)
≤60%
50
%
(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.
Long-Term Debt And Equity Financings (Tables)
Schedule Of Coverage Ratios
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 June 30, 2013, at an assumed annual 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
 
4.4
$
3,633

 
≥2.5
 
110.9
$
2,118

Ameren Illinois
 
≥2.0
 
7.3
 
3,581

(d) 
≥1.5
 
2.7
 
203

(a)
Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b)
Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $485 million and $645 million at Ameren Missouri and Ameren Illinois, respectively.
(c)
Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation.
(d)
Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.
Other Income and Expenses (Tables)
Other Income And Expenses
The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income (loss) for the three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six Months
 
 
2013
 
2012
 
2013
 
2012
 
Ameren:(a)
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
8

 
$
8

 
$
16

  
$
17

 
Interest income on industrial development revenue bonds
7

 
7

 
14

  
14

 
Interest and dividend income
1

 
4

 
1

 
4

 
Other
—

 
—

 
—

  
1

 
Total miscellaneous income
$
16

 
$
19

 
$
31

  
$
36

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
1

 
$
3


$
5

 
$
15

(b) 
Other
4

 
4

 
8

  
7

 
Total miscellaneous expense
$
5

 
$
7

 
$
13

  
$
22

 
Ameren Missouri:
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
7

 
$
7

 
$
14

  
$
15

 
Interest income on industrial development revenue bonds
7

 
7

 
14

 
14

 
Interest and dividend income
—

 
4

 
—

 
4

 
Total miscellaneous income
$
14

 
$
18

 
$
28

  
$
33

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
1

 
$
3

 
$
3

  
$
5

 
Other
2

 
1

 
5

  
2

 
Total miscellaneous expense
$
3

 
$
4

 
$
8

  
$
7

 
Ameren Illinois:
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
1

 
$
1

 
$
2

  
$
2

 
Interest and dividend income
1

 
—

 
1

  
—

 
Other
—

 
1

 
—

  
1

 
Total miscellaneous income
$
2

 
$
2

 
$
3

  
$
3

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
—

 
$
—


$
3

 
$
10

(b) 
Other
1

 
2

 
1

  
3

 
Total miscellaneous expense
$
1

 
$
2

 
$
4

  
$
13

 
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Includes Ameren Illinois’ one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 election to participate in the formula ratemaking process.
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 June 30, 2013, and December 31, 2012:
 
Quantity (in millions, except as indicated)
Commodity
Accrual & NPNS
Contracts(a)
 
Other
Derivatives(b)
 
Derivatives That Qualify
for Regulatory Deferral(c)
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Coal (in tons)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri & Ameren
85

 
96

 
(d)

 
(d)

 
(d)

 
(d)

Fuel oils (in gallons)(e)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri & Ameren
(d)

 
(d)

 
(d)

 
(d)

 
58

 
70

Natural gas (in mmbtu)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
—

 
4

 
—

 
—

 
30

 
19

Ameren Illinois
9

 
16

 
(d)

 
(d)

 
127

 
128

Ameren
9

 
20

 
—

 
—

 
157

 
147

Power (in megawatthours)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
3

 
3

 
1

 
2

 
7

 
9

Ameren Illinois
18

 
21

 
(d)

 
(d)

 
11

 
14

Ameren
21

 
24

 
1

 
2

 
18

 
23

Renewable energy credits(f)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
3

 
3

 
(d)

 
(d)

 
(d)

 
(d)

Ameren Illinois
11

 
12

 
(d)

 
(d)

 
(d)

 
(d)

Ameren
14

 
15

 
(d)

 
(d)

 
(d)

 
(d)

Uranium (pounds in thousands)
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri & Ameren
4,671

 
5,142

 
(d)

 
(d)

 
514

 
446

(a)
Accrual contracts include commodity contracts that do not qualify as derivatives. As of June 30, 2013, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively.
(b)
As of June 30, 2013, these contracts ran through December 2014 for power.
(c)
As of June 30, 2013, these contracts ran through October 2015, October 2019, May 2032, and May 2015 for fuel oils, natural gas, power, and uranium, respectively.
(d)
Not applicable.
(e)
Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil.
(f)
A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power.
Derivative Instruments Carrying Value 
The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2013, and December 31, 2012:
 
Balance Sheet Location
 
Ameren
 
Ameren Missouri
 
Ameren Illinois
2013
 
 
 
 
 
 
Derivative assets not designated as hedging instruments(a)
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
Fuel oils
Other current assets
$
5

$
5

$
—

 
Other assets
 
2

 
2

 
—

Natural gas
Other current assets
 
2

 
1

 
1

 
Other assets
 
1

 
—

 
1

Power
Other current assets
 
45

 
44

 
1

 
Other assets
 
2

 
1

 
1

 
Total assets
$
57

$
53

$
4

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

$
(b)

$
—

 
Other current liabilities
 
—

 
2

 
—

 
Other deferred credits and liabilities
 
2

 
2

 
—

Natural gas
MTM derivative liabilities
 
52

 
(b)

 
45

 
Other current liabilities
 
—

 
7

 
—

 
Other deferred credits and liabilities
 
33

 
5

 
28

Power
MTM derivative liabilities
 
18

 
(b)

 
10

 
Other current liabilities
 
—

 
8

 
—

 
Other deferred credits and liabilities
 
73

 
1

 
72

Uranium
MTM derivative liabilities
 
3

 
(b)

 
—

 
Other current liabilities
 
—

 
3

 
—

 
Total liabilities
$
183

$
28

$
155

2012
 
 
 
 
 
 
Derivative assets not designated as hedging instruments(a)
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
Fuel oils
Other current assets
$
8

$
8

$
—

 
Other assets
 
4

 
4

 
—

Natural gas
Other current assets
 
1

 
—

 
1

 
Other assets
 
1

 
1

 
—

Power
Other current assets
 
14

 
14

 
—

 
Other assets
 
1

 
1

 
—

 
Total assets
$
29

$
28

$
1

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

$
(b)

$
—

 
Other current liabilities
 
—

 
2

 
—

 
Other deferred credits and liabilities
 
2

 
2

 
—

Natural gas
MTM derivative liabilities
 
64

 
(b)

 
56

 
Other current liabilities
 
—

 
8

 
—

 
Other deferred credits and liabilities
 
45

 
7

 
38

Power
MTM derivative liabilities
 
25

 
(b)

 
21

 
Other current liabilities
 
—

 
4

 
—

 
Other deferred credits and liabilities
 
90

 
—

 
90

Uranium
MTM derivative liabilities
 
1

 
(b)

 
—

 
Other current liabilities
 
—

 
1

 
—

 
Other deferred credits and liabilities
 
1

 
1

 
—

 
Total liabilities
$
230

$
25

$
205

(a)
Includes derivatives subject to regulatory deferral.
(b)
Balance sheet line item not applicable to registrant.
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 June 30, 2013, and December 31, 2012:
 
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
2013
 
 
 
 
 
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
 
Fuel oils derivative contracts(a)
$
—

 
$
—

 
$
—

Natural gas derivative contracts(b)
(83
)
 
(12
)
 
(71
)
Power derivative contracts(c)
(43
)
 
37

 
(80
)
Uranium derivative contracts(d)
(3
)
 
(3
)
 
—

2012
 
 
 
 
 
Cumulative gains (losses) deferred in regulatory liabilities or assets:
 
 
 
 
 
Fuel oils derivative contracts(a)
$
4

 
$
4

 
$
—

Natural gas derivative contracts(b)
(107
)
 
(14
)
 
(93
)
Power derivative contracts(c)
(99
)
 
12

 
(111
)
Uranium derivative contracts(d)
(2
)
 
(2
)
 
—

(a)
Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through October 2015 as of June 30, 2013. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013.
(b)
Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2016 at Ameren Illinois as of June 30, 2013. Current gains deferred as regulatory liabilities include $2 million, $1 million, and $1 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $52 million, $7 million, and $45 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2013.
(c)
Represents net gains (losses) associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri as of June 30, 2013. Current gains deferred as regulatory liabilities include $44 million, $43 million, and $1 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $16 million, $6 million, and $10 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2013.
(d)
Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through May 2015 as of June 30, 2013. Current losses deferred as regulatory assets include $3 million and $3 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013.
Offsetting Derivative Assets and Liabilities 
The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of June 30, 2013, and December 31, 2012:
 
 
 
 
Gross Amounts Not Offset in the Balance Sheet
 
 
 
 
Gross Amounts Recognized in the Balance Sheet
 
Derivative Instruments
 
Cash Collateral Received/Posted(a)
 
Net
Amount
2013
 
 
 
 
 
 
 
 
Commodity contracts eligible to be offset:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren
 
$
57

 
$
15

 
$
—

 
$
42

Ameren Missouri
 
53

 
13

 
—

 
40

Ameren Illinois
 
4

 
2

 
—

 
2

Liabilities:
 
 
 
 
 
 
 
 
Ameren
 
$
183

 
$
15

 
$
32

 
$
136

Ameren Missouri
 
28

 
13

 
6

 
9

Ameren Illinois
 
155

 
2

 
26

 
127

2012
 
 
 
 
 
 
 
 
Commodity contracts eligible to be offset:
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren
 
$
29

 
$
10

 
$
—

 
$
19

Ameren Missouri
 
28

 
9

 
—

 
19

Ameren Illinois
 
1

 
1

 
—

 
—

Liabilities:
 
 
 
 
 
 
 
 
Ameren
 
$
230

 
$
10

 
$
65

 
$
155

Ameren Missouri
 
25

 
9

 
7

 
9

Ameren Illinois
 
205

 
1

 
58

 
146

(a)
Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances.
Maximum Exposure If Counterparties Fail 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. 
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Oil and Gas
Companies
 
Total
2013
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
3

 
$
5

 
$
16

 
$
5

  
$
—

 
$
29

Ameren Illinois
—

 
—

 
1

 
—

  
1

 
2

Ameren
$
3

 
$
5

 
$
17

 
$
5

  
$
1

 
$
31

2012
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
2

 
$
3

 
$
14

 
$
3

  
$
—

 
$
22

Ameren Illinois
—

 
—

 
1

 
—

  
—

 
1

Ameren
$
2

 
$
3

 
$
15

 
$
3

  
$
—

 
$
23

Potential Loss On Counterparty Exposures 
The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2013, and December 31, 2012:
 
Commodity
Marketing
Companies
 
Electric
Utilities
 
Financial
Companies
 
Municipalities/
Cooperatives
 
Oil and Gas
Companies
 
Total
2013
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
1

 
$
4

 
$
2

 
$
3

  
$
—

 
$
10

Ameren Illinois
—

 
—

 
—

 
—

  
—

 
—

Ameren
$
1

 
$
4

 
$
2

 
$
3

  
$
—

 
$
10

2012
 
 
 
 
 
 
 
 
 
 
 
Ameren Missouri
$
1

 
$
1

 
$
10

 
$
3

  
$
—

 
$
15

Ameren Illinois
—

 
—

 
—

 
—

  
—

 
—

Ameren
$
1

 
$
1

 
$
10

 
$
3

  
$
—

 
$
15

Derivative Instruments With Credit Risk-Related Contingent Features 
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 June 30, 2013, or December 31, 2012, respectively, and (2) those counterparties with rights to do so requested collateral:
 
Aggregate Fair Value of
Derivative Liabilities(a)
 
Cash
Collateral Posted
 
Potential Aggregate Amount of
Additional  Collateral Required(b)
2013
 
 
 
 
 
Ameren Missouri
$
76

 
$
1

 
$
45

Ameren Illinois
116

 
26

 
82

Ameren
$
192

 
$
27

 
$
127

2012
 
 
 
 
 
Ameren Missouri
$
78

 
$
3

 
$
71

Ameren Illinois
148

 
58

 
84

Ameren
$
226

 
$
61

 
$
155

(a)
Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b)
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the netting effects of such agreements.
Derivatives That Qualify For Regulatory Deferral 
The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and six months ended June 30, 2013, and 2012:
 
 
 
Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets
 
 
 
Three Months
 
Six Months
 
 
 
2013
 
2012
 
2013
 
2012
Ameren
Fuel oils
 
$
(4
)
 
$
(19
)
 
$
(4
)
 
$
(14
)
 
Natural gas
 
(12
)
 
46

 
24

 
28

 
Power(a)
 
36

 
(1
)
 
56

 
(163
)
 
Uranium
 
(1
)
 
—

 
(1
)
 
—

 
Total
 
$
19

 
$
26

 
$
75

 
$
(149
)
Ameren Missouri
Fuel oils
 
$
(4
)
 
$
(19
)
 
$
(4
)
 
$
(14
)
 
Natural gas
 
(2
)
 
5

 
2

 
3

 
Power
 
35

 
4

 
25

 
3

 
Uranium
 
(1
)
 
—

 
(1
)
 
—

 
Total
 
$
28

 
$
(10
)
 
$
22

 
$
(8
)
Ameren Illinois
Natural gas
 
$
(10
)
 
$
41

 
$
22

 
$
25

 
Power
 
1

 
63

 
31

 
(81
)
 
Total
 
$
(9
)
 
$
104

 
$
53

 
$
(56
)
(a)
Amounts include intercompany eliminations.
Fair Value Measurements (Tables)
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Valuation Techniques 
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of June 30, 2013:
 
 
Fair Value
 
 
 
Weighted
 
 
Assets
Liabilities
Valuation Technique
Unobservable Input
Range
Average
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
7

$
(4
)
Option model
Volatilities(%)(b)
8 - 32
20
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 3
2
 
Natural gas
2

(1
)
Option model
Volatilities(%)(b)
1 - 31
24
 
 
 
 
 
Nodal basis($/mmbtu)(c)
(0.35) - (0.06)
(0.3)
 
 
 
 
Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.1) - 0
0
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 2
1
 
 
 
 
 
Ameren credit risk(%)(c)(d)
3
(f)
 
Power(e)
44

(87
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c)
25 - 49
32
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(767) - 1,790
252
 
 
 
 
 
Nodal basis($/MWh)(c)
(4) - (1)
(3)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 7
3
 
 
 
 
 
Ameren credit risk(%)(c)(d)
3
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
5 - 8
6
 
 
 
 
 
Escalation rate(%)(b)(g)
4 - 5
4
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
40 - 44
40
Ameren Missouri
Fuel oils
$
7

$
(4
)
Option model
Volatilities(%)(b)
8 - 32
20
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 3
2
 
Natural gas
—

(1
)
Option model
Volatilities(%)(b)
1 - 31
24
 
 
 
 
 
Nodal basis($/mmbtu)(c)
(0.35) - (0.06)
(0.3)
 
 
 
 
Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.1) - 0
(0.1)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 2
1
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
3
(f)
 
Power(e)
42

(5
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c)
25 - 49
38
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(767) - 1,790
252
 
 
 
 
 
Nodal basis($/MWh)(c)
(4) - (1)
(2)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.22 - 3
3
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
3
(f)
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
40 - 44
40
Ameren Illinois
Natural gas
$
2

$
—

Option model
Volatilities(%)(b)
1 - 31
27
 
 
 
 
 
Nodal basis($/mmbtu)(c)
(0.3) - (0.27)
(0.28)
 
 
 
 
Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.1) - 0
0
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.69 - 2
1
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
3
(f)
 
Power(e)
2

(82
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(b)
26 - 39
30
 
 
 
 
 
Nodal basis($/MWh)(b)
(4) - (1)
(3)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
7
(f)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
3
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
5 - 8
6
 
 
 
 
 
Escalation rate(%)(b)(g)
4 - 5
4
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(c)
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(d)
Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances.
(e)
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.
(f)
Not applicable.
(g)
Escalation rate applies to power prices 2026 and beyond.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012:
 
 
Fair Value
 
 
 
Weighted
 
 
Assets
Liabilities
Valuation Technique
Unobservable Input
Range
Average
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
8

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

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

(2
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
43 - 46
44
Ameren Missouri
Fuel oils
$
8

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

(3
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c)
24 - 56
36
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(281) - 1,851
178
 
 
 
 
 
Nodal basis($/MWh)(c)
(5) - (1)
(2)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
.22 - 1
1
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
2
(e)
 
Uranium
—

(2
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
43 - 46
44
Ameren Illinois
Power(f)
$
—

$
(111
)
Discounted cash flow
Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(b)
22 - 47
30
 
 
 
 
 
Nodal basis($/MWh)(b)
(5) - (1)
(3)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
5
(e)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 8
6
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(c)
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(d)
Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances.
(e)
Not applicable.
(f)
Power valuations utilize visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand.
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 June 30, 2013:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
—

 
$
—

 
$
7

 
$
7

 
Natural gas
 
—

 
1

 
2

 
3

 
Power
 
—

 
3

 
44

 
47

 
Total derivative assets - commodity contracts
 
$
—

 
$
4

 
$
53

 
$
57

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
294

 
—

 
—

 
294

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
40

 
—

 
40

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
91

 
—

 
91

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
297

 
$
143

 
$
—

 
$
440

 
Total Ameren
 
$
297

 
$
147

 
$
53

 
$
497

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
—

 
$
—

 
$
7

 
$
7

 
Natural gas
 
—

 
1

 
—

 
1

 
Power
 
—

 
3

 
42

 
45

 
Total derivative assets - commodity contracts
 
$
—

 
$
4

 
$
49

 
$
53

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
294

 
—

 
—

 
294

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
40

 
—

 
40

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
91

 
—

 
91

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
297

 
$
143

 
$
—

 
$
440

 
Total Ameren Missouri
 
$
297

 
$
147

 
$
49

 
$
493

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
—

 
$
2

 
$
2

 
Power
 
—

 
—

 
2

 
2

 
Total Ameren Illinois
 
$
—

 
$
—

 
$
4

 
$
4

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

 
$
—

 
$
4

 
$
4

 
Natural gas
 
5

 
79

 
1

 
85

 
Power
 
—

 
4

 
87

 
91

 
Uranium
 
—

 
—

 
3

 
3

 
Total Ameren
 
$
5

 
$
83

 
$
95

 
$
183

Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
—

 
$
—

 
$
4

 
$
4

 
Natural gas
 
5

 
6

 
1

 
12

 
Power
 
—

 
4

 
5

 
9

 
Uranium
 
—

 
—

 
3

 
3

 
Total Ameren Missouri
 
$
5

 
$
10

 
$
13

 
$
28

Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
73

 
$
—

 
$
73

 
Power
 
—

 
—

 
82

 
82

 
Total Ameren Illinois
 
$
—

 
$
73

 
$
82

 
$
155

(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, 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:
 
 
 
 
 
 
 
 
 
Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
4

 
$
—

 
$
8

 
$
12

 
Natural gas
 
—

 
2

 
—

 
2

 
Power
 
—

 
1

 
14

 
15

 
Total derivative assets - commodity contracts
 
$
4

 
$
3

 
$
22

 
$
29

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
264

 
—

 
—

 
264

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
47

 
—

 
47

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
81

 
—

 
81

 
Asset-backed securities
 
—

 
11

 
—

 
11

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
265

 
$
141

 
$
—

 
$
406

 
Total Ameren
 
$
269

 
$
144

 
$
22

 
$
435

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
4

 
$
—

 
$
8

 
$
12

 
Natural gas
 
—

 
1

 
—

 
1

 
Power
 
—

 
1

 
14

 
15

 
Total derivative assets - commodity contracts
 
$
4

 
$
2

 
$
22

 
$
28

 
Nuclear Decommissioning Trust Fund(b):
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
264

 
—

 
—

 
264

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
47

 
—

 
47

 
Municipal bonds
 
—

 
1

 
—

 
1

 
U.S. treasury and agency securities
 
—

 
81

 
—

 
81

 
Asset-backed securities
 
—

 
11

 
—

 
11

 
Other
 
—

 
1

 
—

 
1

 
Total Nuclear Decommissioning Trust Fund
 
$
265

 
$
141

 
$
—

 
$
406

 
Total Ameren Missouri
 
$
269

 
$
143

 
$
22

 
$
434

Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
1

 
$
—

 
$
1

 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total    
Liabilities:
 
 
 
 
 
 
 
 
 
Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
1

 
$
—

 
$
3

 
$
4

 
Natural gas
 
7

 
102

 
—

 
109

 
Power
 
—

 
1

 
114

 
115

 
Uranium
 
—

 
—

 
2

 
2

 
Total Ameren
 
$
8

 
$
103

 
$
119

 
$
230

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

 
$
—

 
$
3

 
$
4

 
Natural gas
 
7

 
8

 
—

 
15

 
Power
 
—

 
1

 
3

 
4

 
Uranium
 
—

 
—

 
2

 
2

 
Total Ameren Missouri
 
$
8

 
$
9

 
$
8

 
$
25

Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
Illinois
Natural gas
 
$
—

 
$
94

 
$
—

 
$
94

 
Power
 
—

 
—

 
111

 
111

 
Total Ameren Illinois
 
$
—

 
$
94

 
$
111

 
$
205

(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Balance excludes $2 million of receivables, payables, and accrued income, net.
Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level Three 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 for the three months ended June 30, 2013:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
5

$
(a)

$
5

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Ending balance at June 30, 2013
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
Natural gas:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
—

$
2

$
2

Realized and unrealized gains (losses):
 

 

 

Included in regulatory assets/liabilities
 
—

 
—

 
—

Total realized and unrealized gains (losses)
 
—

 
—

 
—

Purchases
 
(1
)
 
—

 
(1
)
Ending balance at June 30, 2013
$
(1
)
$
2

$
1

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
—

$
(1
)
Power:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
2

$
(81
)
$
(79
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
1

 
1

 
2

Total realized and unrealized gains (losses)
 
1

 
1

 
2

Purchases
 
40

 
—

 
40

Settlements
 
(9
)
 
—

 
(9
)
Transfers out of Level 3
 
3

 
—

 
3

Ending balance at June 30, 2013
$
37

$
(80
)
$
(43
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
3

$
(4
)
$
(1
)
Uranium:
 
 
 
 
 
 
Beginning balance at April 1, 2013
$
(2
)
$
(a)

$
(2
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Settlements
 
1

 
(a)

 
1

Ending balance at June 30, 2013
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
(a)
Not applicable.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2012:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at April 1, 2012
$
7

$
(a)

$
7

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(4
)
 
(a)

 
(4
)
Total realized and unrealized gains (losses)
 
(4
)
 
(a)

 
(4
)
Purchases
 
2

 
(a)

 
2

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(1
)
 
(a)

 
(1
)
Ending balance at June 30, 2012
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
(2
)
$
(a)

$
(2
)
Power(b):
 
 
 
 
 
 
Beginning balance at April 1, 2012
$
20

$
(284
)
$
(82
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(4
)
 
(1
)
 
(10
)
Total realized and unrealized gains (losses)
 
(4
)
 
(1
)
 
(10
)
Purchases
 
22

 
—

 
22

Settlements
 
(11
)
 
64

 
(10
)
Transfers out of Level 3
 
(1
)
 
—

 
(1
)
Ending balance at June 30, 2012
$
26

$
(221
)
$
(81
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
(1
)
$
(6
)
 $
5

Uranium:
 
 
 
 
 
 
Beginning balance at April 1, 2012
$
(1
)
 
(a)

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

 
(a)

 
—

Total realized and unrealized gains (losses)
 
—

 
(a)

 
—

Ending balance at June 30, 2012
$
(1
)
 
(a)

$
(1
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
—

 
(a)

$
—

(a)
Not applicable.
(b)
Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2013:
  
 
Net derivative commodity contracts
Six Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
5

$
(a)

$
5

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Purchases
 
1

 
(a)

 
1

Settlements
 
(1
)
 
(a)

 
(1
)
Ending balance at June 30, 2013
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
Natural gas:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
—

$
—

$
—

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

 
1

 
1

Total realized and unrealized gains (losses)
 
—

 
1

 
1

Purchases
 
(1
)
 
1

 
—

Ending balance at June 30, 2013
$
(1
)
$
2

$
1

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
—

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
11

$
(111
)
$
(100
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
6

 
15

 
21

Total realized and unrealized gains (losses)
 
6

 
15

 
21

Purchases
 
40

 
—

 
40

Settlements
 
(22
)
 
16

 
(6
)
Transfers into Level 3
 
(2
)
 
—

 
(2
)
Transfers out of Level 3
 
4

 
—

 
4

Ending balance at June 30, 2013
$
37

$
(80
)
$
(43
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
—

$
15

$
15

Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
(2
)
$
(a)

$
(2
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Settlements
 
1

 
(a)

 
1

Ending balance at June 30, 2013
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013
$
(1
)
$
(a)

$
(1
)
(a)
Not applicable.
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2012:
  
 
Net derivative commodity contracts
Six Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
3

$
(a)

$
3

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(a)

 
(2
)
Total realized and unrealized gains (losses)
 
(2
)
 
(a)

 
(2
)
Purchases
 
2

 
(a)

 
2

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(1
)
 
(a)

 
(1
)
          Transfers into Level 3
 
2

 
(a)

 
2

Ending balance at June 30, 2012
$
3

$
(a)

$
3

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
(1
)
$
(a)

$
(1
)
Natural gas:
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
(14
)
$
(160
)
$
(174
)
Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
(2
)
 
(26
)
 
(28
)
Total realized and unrealized gains (losses)
 
(2
)
 
(26
)
 
(28
)
Settlements
 
1

 
16

 
17

          Transfers out of Level 3
 
15

 
170

 
185

Ending balance at June 30, 2012
$
—

$
—

$
—

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
9

$
114

$
123

Power(b):
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
21

$
(140
)
$
81

Realized and unrealized gains (losses):
 
 
 
 
 
 
Included in regulatory assets/liabilities
 
9

 
(221
)
 
(168
)
Total realized and unrealized gains (losses)
 
9

 
(221
)
 
(168
)
Purchases
 
22

 
—

 
22

Settlements
 
(24
)
 
140

 
(14
)
Transfers out of Level 3
 
(2
)
 
—

 
(2
)
Ending balance at June 30, 2012
$
26

$
(221
)
$
(81
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
3

$
(195
)
(c) $
(179
)
Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2012
$
(1
)
$
(a)

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

 
(a)

 
—

Total realized and unrealized gains (losses)
 
—

 
(a)

 
—

Ending balance at June 30, 2012
$
(1
)
$
(a)

$
(1
)
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012
$
—

$
(a)

$
—

(a)
Not applicable.
(b)
Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company.
(c)
The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois’ swap contracts, which expire May 2032.
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 three and six months ended June 30, 2013, and 2012:
 
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
Ameren - derivative commodity contracts:
 
 
 
 
 
 
 
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
—

 
$
—

 
$
—

 
$
2

Transfers out of Level 3 / Transfers into Level 2 - Natural gas
—

 
—

 
—

 
185

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

 
—

 
(2
)
 
—

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

 
(1
)
 
4

 
(2
)
Net fair value of Level 3 transfers
$
3

 
$
(1
)
 
$
2

 
$
185

Ameren Missouri - derivative commodity contracts:
 
 
 
 
 
 
 
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils
$
—

 
$
—

 
$
—

 
$
2

Transfers out of Level 3 / Transfers into Level 2 - Natural gas
—

 
—

 
—

 
15

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

 
—

 
(2
)
 
—

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

 
(1
)
 
4

 
(2
)
Net fair value of Level 3 transfers
$
3

 
$
(1
)
 
$
2

 
$
15

Ameren Illinois - derivative commodity contracts:
 
 
 
 
 
 
 
Transfers out of Level 3 / Transfers into Level 2 - Natural gas
$
—

 
$
—

 
$
—

 
$
170

Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt, Capital Lease Obligations And Preferred Stock 
The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at June 30, 2013, and December 31, 2012:
  
June 30, 2013
 
December 31, 2012
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Ameren:(a)(b)
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
6,158

 
$
6,864

 
$
6,157

 
$
7,110

Preferred stock
142

 
124

 
142

 
123

Ameren Missouri:
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
4,006

 
$
4,470

 
$
4,006

 
$
4,625

Preferred stock
80

 
75

 
80

 
73

Ameren Illinois:
 
 
 
 
 
 
 
Long-term debt (including current portion)
$
1,727

 
$
1,940

 
$
1,727

 
$
2,020

Preferred stock
62

 
49

 
62

 
49

(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)
Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet.
Related Party Transactions (Tables)
Schedule of Related Party Transactions
The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three and six months ended June 30, 2013, and 2012. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 4 - Short-term Debt and Liquidity of this report.
  
  
 
  
 
Three Months
 
Six Months
Agreement
Income Statement
Line Item
 
  
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Missouri
 
Ameren
Illinois
Ameren Missouri power supply
Operating Revenues
 
2013
$
(b)

$
(a)
$
1
$
(a)

agreements with Ameren Illinois
 
 
2012
 
(b)

 
(a)

 
(b)
 
(a)

Ameren Missouri and Ameren Illinois
Operating Revenues
 
2013
 
5

 
(b)

 
11
 
(b)

rent and facility services
 
 
2012
 
5

 
(b)

 
9
 
(b)

Ameren Missouri and Genco gas
Operating Revenues
 
2013
 
(b)

 
(a)

 
(b)
 
(a)

transportation agreement
 
 
2012
 
(b)

 
(a)

 
(b)
 
(a)

Transmission services agreement
Operating Revenues
 
2013
 
(a)

 
7

 
(a)
 
13

with Marketing Company
 
 
2012
 
(a)

 
3

 
(a)
 
5

Total Operating Revenues
 
 
2013
$
5

$
7

$
12
$
13

 
 
 
2012
 
5

 
3

 
9
 
5

Ameren Illinois power supply
Purchased Power
 
2013
$
(a)

$
22

$
(a)
$
48

agreements with Marketing Company
 
 
2012
 
(a)

 
72

 
(a)
 
160

Ameren Illinois power supply
Purchased Power
 
2013
 
(a)

 
(b)

 
(a)
 
1

agreements with Ameren Missouri
 
 
2012
 
(a)

 
(b)

 
(a)
 
(b)

Total Purchased Power
 
 
2013
$
(a)

$
22

$
(a)
$
49

 
 
 
2012
 
(a)

 
72

 
(a)
 
160

Ameren Services support services
Other Operations and Maintenance
 
2013
$
28

$
24

$
60
$
48

agreement

 
2012
 
27

 
22

 
55
 
45

Insurance premiums(c)
Other Operations and Maintenance
 
2013
 
(b)

 
(a)

 
(b)
 
(a)

 

 
2012
 
(b)

 
(a)

 
(b)
 
(a)

Total Other Operations and
 
 
2013
$
28

$
24

$
60
$
48

Maintenance Expenses
 
 
2012
 
27

 
22

 
55
 
45

Money pool borrowings (advances)
Interest Charges
 
2013
$
__

$
(b)

$
(b)
$
(b)

 
 
 
2012
 
__

 
(b)

 
__
 
(b)

(a)
Not applicable.
(b)
Amount less than $1 million.
(c)
Represents insurance premiums paid to Missouri Energy Risk Assurance Company, an affiliate, for replacement power
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 June 30, 2013. 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
for Single Incidents
 
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) 
Missouri Energy Risk Assurance Company
$
64

(g) 
$
—

  
(a)
Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b)
Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $17.5 million per year.
(c)
Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $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)
First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-radiation events. Effective July 1, 2013, an additional non-radiation limit of $200 million in excess of the $1.5 billion was made available. This additional coverage is a shared limit with other generators purchasing this coverage and includes one free reinstatement. Effective August 1, 2013, $500 million in excess of the $2.25 billion property coverage and $1.7 billion non-radiation coverage was provided by European Mutual Association for Nuclear Insurance. Concurrently, the Nuclear Electric Insurance Ltd. property limit for nuclear events was reduced by $500 million.
(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 replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Effective April 1, 2013, non-radiation events are sub-limited to $327.6 million.
(g)
Provides replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 9 - Related Party Transactions for more information on this affiliate transaction.
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 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 June 30, 2013, the estimated obligation to complete the remediation of these former MGP sites.
  
Estimate
 
Recorded
  Liability(a)
  
Low
 
High
 
Ameren
$
256

 
$
339

 
$
256

Ameren Missouri
5

 
6

 
5

Ameren Illinois
251

 
333

 
251

(a)
Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was a better estimate.
Schedule of Asbestors-Related Litigation Pending Lawsuits 
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of June 30, 2013:
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Total(a)
2
 
58
 
68
 
90
(a)
Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
Retirement Benefits (Tables)
Components Of Net Periodic Benefit Cost 
The following table presents the components of the net periodic benefit cost for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 2013, and 2012:
  
Pension Benefits (a)
 
Postretirement Benefits (a)
 
Three Months
 
Six Months
 
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Service cost
$
22

 
$
20

 
$
46

 
$
41

 
$
5

 
$
5

 
$
11

 
$
11

Interest cost
41

 
41

 
81

 
83

 
11

 
11

 
23

 
24

Expected return on plan assets
(54
)
 
(52
)
 
(108
)
 
(104
)
 
(15
)
 
(14
)
 
(31
)
 
(28
)
Amortization of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
(1
)
 
(1
)
 
(2
)
 
(2
)
 
(1
)
 
(1
)
 
(2
)
 
(2
)
Actuarial loss
24

 
18

 
46

 
37

 
2

 
(1
)
 
4

 
2

Net periodic benefit cost
$
32

 
$
26

 
$
63

 
$
55

 
$
2

 
$
—

 
$
5

 
$
7

(a)
Excludes the EEI plans as they are included in discontinued operations.
Summary Of Benefit Plan Costs Incurred 
Ameren Missouri and Ameren Illinois are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and six months ended June 30, 2013, and 2012:
  
Pension Costs
 
Postretirement Costs
 
Three Months
 
Six Months
 
Three Months
 
Six Months
  
2013
 
2012
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Ameren Missouri
$
18

 
$
16

 
$
36

 
$
32

 
$
2

 
$
—

 
$
5

 
$
5

Ameren Illinois
11

 
8

 
21

 
18

 
(1
)
 
—

 
—

 
2

Other
3

 
2

 
6

 
5

 
1

 
—

 
—

 
—

Ameren(a)
$
32

 
$
26

 
$
63

 
$
55

 
$
2

 
$
—

 
$
5

 
$
7

(a)
Includes amounts for Ameren registrants and nonregistrant subsidiaries, but excludes the EEI plans as they are included in discontinued operations.
Segment Information (Tables)
Schedule Of Segment Reporting Information By Segment
The following table presents information about the revenues and specified items included in net income attributable to Ameren Corporation from continuing operations for the three and six months ended June 30, 2013, and 2012, and total assets as of June 30, 2013, and December 31, 2012.
Three Months
Ameren
Missouri
 
Ameren
Illinois
 
Other
 
Intersegment
Eliminations
 
Consolidated
 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
883

 
$
514

 
$
6

 
$
—

 
$
1,403

 
Intersegment revenues
6

 
2

 
—

 
(8
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
84

 
31

 
(10
)
 
—

 
105

 
2012
 
 
 
 
 
 
 
 
 
 
External revenues
$
838

 
$
564

 
$
—

 
$
—

 
$
1,402

 
Intersegment revenues
6

 
—

 
1

 
(7
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
143

 
32

 
(14
)

—

 
161

 
Six Months
  
 
  
 
  
 
  
 
  
 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,672

 
$
1,197

 
$
9

  
$
—

 
$
2,878

 
Intersegment revenues
13

 
3

 
1

  
(17
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
124

 
62

 
(27
)
  
—

 
159

 
2012
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,524

 
$
1,288

 
$
2

  
$
—

 
$
2,814

 
Intersegment revenues
11

 
—

 
2

  
(13
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
164

 
59

 
(25
)
 
—

 
198

 
As of June 30, 2013:
 
 
 
 
 
 
 
 
 
 
Total assets
$
13,131

 
$
7,366

 
$
1,354

 
$
(1,061
)
 
$
20,790

(a) 
As of December 31, 2012:
 
 
 
 
 
 
 
 
 
 
Total assets
$
13,043

 
$
7,282

 
$
1,228

 
$
(944
)
 
$
20,609

(a) 
(a)    Excludes “Current assets of discontinued operations.” See Note 2 - Divestiture Transactions and Discontinued Operations for additional information.
Summary Of Significant Accounting Policies (Narrative) (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 6 Months Ended 1 Months Ended 6 Months Ended 0 Months Ended
Sep. 30, 2012
Jun. 30, 2012
Mar. 31, 2012
Jun. 30, 2013
Dec. 31, 2012
Sep. 30, 2012
Ameren Missouri [Member]
Jun. 30, 2012
Ameren Missouri [Member]
Mar. 31, 2012
Ameren Missouri [Member]
Jun. 30, 2013
Ameren Missouri [Member]
Dec. 31, 2012
Ameren Missouri [Member]
Jun. 30, 2013
Ameren Illinois Company [Member]
Jun. 30, 2013
Electric Energy, Inc [Member]
Dec. 31, 2012
Electric Energy, Inc [Member]
Jan. 31, 2013
Performance Shares [Member]
Jun. 30, 2013
Performance Shares [Member]
Mar. 14, 2013
Elgin, Gibson City and Grand Tower Energy Centers [Member]
Ameren Energy Generating Company [Member]
Basis Of Presentation And Significant Accounting Policies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership interest
 
 
 
 
 
 
 
 
 
 
 
80.00% 
 
 
 
 
Initial payment received
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 100 
Identified immaterial errors
49 
26 
14 
 
 
49 
26 
14 
 
 
 
 
 
 
 
 
Fair value of each share unit, per share
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 31.19 
$ 31.19 1
 
Closing common share price
 
 
 
 
$ 30.72 
 
 
 
 
 
 
 
 
 
 
 
Performance period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3 years 
 
Three-year risk-free rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.36% 
 
Volatility rate, minimum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12.00% 
 
Volatility rate, maximum
 
 
 
 
 
 
 
 
 
 
 
 
 
 
21.00% 
 
Book value or renewable energy credits
 
 
 
18 
14 
 
 
 
18 
14 
 
 
 
 
 
 
Unrecognized tax benefits
 
 
 
193 
 
 
 
 
127 
 
4 
 
 
 
 
 
Unrecognized tax benefits (detriments) that would impact effective tax rate
 
 
 
49 
 
 
 
 
1 
 
(1)
 
 
 
 
 
Increase in unrecognized tax benefits that would impact effective tax rate
 
 
 
48 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated unrecognized tax decreases resulting from settlements with taxing authorities
 
 
 
$ 126 
 
 
 
 
$ 110 
 
$ 5 
 
 
 
 
 
Percentage of EEI not owned by Ameren
 
 
 
 
 
 
 
 
 
 
 
20.00% 
20.00% 
 
 
 
Summary Of Significant Accounting Policies (Schedule Of Amortization Expense Based On Usage Of Renewable Energy Credits And Emission Allowances) (Detail) (REC and Emission Allowances [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Amortization of intangible assets
$ 3 
$ 1 1
$ 7 
$ 1 1
Ameren Missouri [Member]
 
 
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Amortization of intangible assets
   
1 1
1 1
1 1
Ameren Illinois Company [Member]
 
 
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Amortization of intangible assets
$ 3 
$ 1 1
$ 7 
$ 1 1
Summary Of Significant Accounting Policies (Schedule Of Excise Taxes) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Accounting Policies [Line Items]
 
 
 
 
Excise tax expense
$ 49 
$ 48 
$ 104 
$ 93 
Ameren Missouri [Member]
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
Excise tax expense
38 
38 
71 
65 
Ameren Illinois Company [Member]
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
Excise tax expense
$ 11 
$ 10 
$ 33 
$ 28 
Summary Of Significant Accounting Policies (Equity Changes Attributable To Noncontrolling Interest) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Electric Energy, Inc [Member]
Dec. 31, 2012
Electric Energy, Inc [Member]
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
 
 
 
 
 
 
Noncontrolling interest, beginning of period
$ 151 1
$ 147 1
$ 151 1
$ 149 
 
 
Net income from continuing operations attributable to noncontrolling interests
1 
1 
3 
3 
 
 
Net income (loss) from discontinued operations attributable to noncontrolling interests
   
(2)
   
(4)
 
 
Dividends paid to noncontrolling interest holders
(1)
(1)
(3)
(3)
 
 
Noncontrolling interest, end of period
$ 151 1
$ 145 1
$ 151 1
$ 145 1
 
 
Percentage of EEI not owned by Ameren
 
 
 
 
20.00% 
20.00% 
Divestiture Transactions and Discontinued Operations (Narrative) (Details) (USD $)
0 Months Ended 3 Months Ended 6 Months Ended
Mar. 14, 2013
Jun. 30, 2013
Mar. 31, 2013
Jun. 30, 2013
center
Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Transaction Agreement, Closing, Extension Period
1 month 
 
 
 
 
New Ameren Energy Resources Company, LLC [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Impairment of assets to be disposed of
 
$ 13,000,000 
$ 155,000,000 
$ 168,000,000 
 
Discontinued operations deferred tax expense
 
1,000,000 
98,000,000 
97,000,000 
 
Discontinued operations deferred tax benefit
 
6,000,000 
63,000,000 
69,000,000 
 
Number of energy centers impaired
 
 
 
3 
 
Disposal group, fair value
 
 
 
 
133,000,000 
Obligation to provide credit support, period
24 months 
 
 
 
 
Buyer's indemnification guarantee obligation
25,000,000 
 
 
 
 
Buyer's indemnification guarantee obligation, period
24 months 
 
 
 
 
Period for working capital adjustment
120 days 
 
 
 
 
Transitional services to be provided to buyer, period
6 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
5,000,000 
 
 
 
 
Transitional services to be provided to buyer, additional period
6 months 
 
 
 
 
Meredosia and Hutsonville Energy Centers [Member] |
Ameren Energy Generating Company [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Asset retirement obligation
 
27,000,000 
 
27,000,000 
 
Notes Payable, Other Payables [Member] |
New Ameren Energy Resources Company, LLC [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Converted instrument, period for conversion
24 months 
 
 
 
 
Cash Collateral for Borrowed Securities
 
29,000,000 
 
29,000,000 
 
Senior Notes [Member] |
Ameren Energy Generating Company [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Aggregate principal amount of senior notes
 
825,000,000 
 
825,000,000 
 
Illinois Power Holdings, LLC [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Pension and other postretirement obligations assumed by counterparty
 
37,000,000 
 
37,000,000 
 
Defined benefit plan assets assumed by counterparty
 
15,000,000 
 
15,000,000 
 
Transaction agreement, cash retained by counterparty
 
85,000,000 
 
85,000,000 
 
Elgin, Gibson City and Grand Tower Energy Centers [Member] |
Ameren Energy Generating Company [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Proceeds from sale of property, plant, and equipment
100,000,000 
 
 
 
 
Significant Acquisitions and Disposals, Number Appraisers
3 
 
 
 
 
Expected additional proceeds from sale of assets, minimum
33,000,000 
 
 
 
 
Expected proceeds from sale of assets, minimum
$ 133,000,000 
 
 
 
 
Maximum [Member] |
New Ameren Energy Resources Company, LLC [Member]
 
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
Transitional services to be provided to buyer, period
12 months 
 
 
 
 
Divestiture Transactions and Discontinued Operations (Components of Discontinued Operations in Consolidated Statement of Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
New Ameren Energy Resources Company, LLC [Member]
Mar. 31, 2013
New Ameren Energy Resources Company, LLC [Member]
Jun. 30, 2013
New Ameren Energy Resources Company, LLC [Member]
Jun. 30, 2012
Duck Creek Energy Center [Member]
New Ameren Energy Resources Company, LLC [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
Operating revenues
$ 303 
$ 258 
$ 567 
$ 504 
 
 
 
 
Operating expenses
(310)
(238)
(725)1
(1,064)2
 
 
 
 
Operating income (loss)
(7)
20 
(158)
(560)
 
 
 
 
Other income (loss)
1 
   
(1)
0 
 
 
 
 
Interest charges
(11)
(14)
(22)
(29)
 
 
 
 
Income (loss) before income taxes
(17)
6 
(181)
(589)
 
 
 
 
Income tax (expense) benefit
7 
42 
(28)
195 
 
 
 
 
Income (Loss) from discontinued operations, net of taxes
(10)
48 
(209)
(394)
 
 
 
 
Impairment of Long-Lived Assets to be Disposed of
 
 
 
 
$ 13 
$ 155 
$ 168 
$ 628 
Divestiture Transactions and Discontinued Operations (Components of Assets and Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Current assets of discontinued operations
 
 
Cash and cash equivalents
$ 25 
$ 25 
Accounts receivable and unbilled revenue
102 
102 
Materials and supplies
119 
134 
Mark-to-market derivative assets
111 
102 
Property and plant, net
615 
748 
Accumulated deferred income taxes, net
380 
373 
Other assets
134 
116 
Total current assets of discontinued operations
1,486 
1,600 
Current liabilities of discontinued operations
 
 
Accounts payable and other current obligations
142 
133 
Mark-to-market derivative liabilities
70 
63 
Long-term debt, net
824 
824 
Asset retirement obligations
87 
78 
Pension and other postretirement benefits
37 
40 
Other liabilities
23 
28 
Total current liabilities of discontinued operations
1,183 
1,166 
Accumulated other comprehensive gain (loss)
8 1
19 1
Noncontrolling Interest
$ 8 2
$ 8 2
Electric Energy, Inc [Member]
 
 
Current liabilities of discontinued operations
 
 
Percentage of EEI not owned by Ameren
20.00% 
20.00% 
Divestiture Transactions and Discontinued Operations (Debt Ratios) (Details) (Ameren Energy Generating Company [Member])
6 Months Ended
Jun. 30, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
Restricted payment interest coverage ratio, Actual
1.60 1 2
Additional indebtedness debt-to-capital ratio, Actual
0.50 1
Minimum [Member]
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
Additional indebtedness debt-to-capital ratio, Actual
0.60 1
Restricted payment interest coverage ratio, Required
1.75 2
Additional indebtedness interest coverage ratio, Required
2.5 1
Rate And Regulatory Matters (Narrative-Missouri) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 1 Months Ended 6 Months Ended 3 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Ameren Missouri [Member]
Jun. 30, 2012
Ameren Missouri [Member]
Jun. 30, 2013
Ameren Missouri [Member]
Jun. 30, 2012
Ameren Missouri [Member]
Apr. 30, 2011
Ameren Missouri [Member]
Fac Prudence Review [Member]
Jul. 31, 2011
Ameren Missouri [Member]
Accounting Authority Order Request [Member]
Dec. 30, 2012
Electric Distribution [Member]
Ameren Missouri [Member]
Final Rate Order [Member]
Jun. 30, 2013
Fac Prudence Review [Member]
Subsequent Periods After September 30, 2009 [Member]
Jun. 30, 2013
Fac Prudence Review [Member]
Subsequent Periods After September 30, 2009 [Member]
MoPSC order [Member]
Jun. 30, 2013
Fac Prudence Review [Member]
Subsequent Periods After September 30, 2009 [Member]
Ameren Missouri [Member]
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contested amounts under the FAC
 
 
 
 
 
 
 
 
$ 18 
 
 
$ 3 
$ 26 
$ 23 
Interest Charges
100 
98 
201 
196 
56 
56 
116 
112 
1 
 
 
 
1 
1 
Request to defer fixed costs not recovered from Noranda, amount
 
 
 
 
 
 
 
 
 
36 
 
 
 
 
Authorized Increase in Revenue from Utility Service
 
 
 
 
 
 
 
 
 
 
$ 260 
 
 
 
Rate And Regulatory Matters (Narrative-Illinois) (Detail) (Ameren Illinois Company [Member], USD $)
12 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended 0 Months Ended 0 Months Ended 1 Months Ended
Jun. 30, 2013
Electric Distribution [Member]
Dec. 31, 2012
Electric Distribution [Member]
Final Rate Order [Member]
Dec. 31, 2012
Electric Distribution [Member]
Rate order appeal [Member]
Jul. 30, 2013
Ameren Illinois Company Position [Member]
Electric Distribution [Member]
Jul. 31, 2013
Ameren Illinois Company Position [Member]
Electric Distribution [Member]
Jul. 31, 2013
Ameren Illinois Company Position [Member]
Gas Distribution [Member]
Pending Rate Case [Member]
Jul. 2, 2013
Icc Staff Recommendation [Member]
Electric Distribution [Member]
Jul. 31, 2013
Icc Staff Recommendation [Member]
Electric Distribution [Member]
Aug. 8, 2013
Icc Staff Recommendation [Member]
Gas Distribution [Member]
Pending Rate Case [Member]
Jul. 30, 2013
Increase in recoverable costs [Member]
Ameren Illinois Company Position [Member]
Ieima [Member]
Electric Distribution [Member]
Jul. 2, 2013
Increase in recoverable costs [Member]
Icc Staff Recommendation [Member]
Ieima [Member]
Electric Distribution [Member]
Jun. 30, 2013
Revenue Requirement Reconcilation Adjustment [Member]
Electric Distribution [Member]
Dec. 31, 2012
Revenue Requirement Reconcilation Adjustment [Member]
Electric Distribution [Member]
Jul. 30, 2013
Revenue Requirement Reconcilation Adjustment [Member]
Ameren Illinois Company Position [Member]
Electric Distribution [Member]
Jul. 2, 2013
Revenue Requirement Reconcilation Adjustment [Member]
Icc Staff Recommendation [Member]
Ieima [Member]
Electric Distribution [Member]
Jan. 31, 2013
Minimum [Member]
Gas Distribution [Member]
Pending Rate Case [Member]
Jan. 31, 2013
Maximum [Member]
Gas Distribution [Member]
Pending Rate Case [Member]
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
$ 33,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue requirement
 
765,000,000 
 
 
783,000,000 
 
 
772,000,000 
 
 
 
 
 
 
 
 
 
Requested rate decrease, amount
 
 
11,000,000 
(38,000,000)
 
50,000,000 
(60,000,000)
 
24,000,000 
18,000,000 
8,000,000 
 
 
(56,000,000)
(68,000,000)
 
 
Rate Of Return On Common Equity
 
 
 
 
 
10.40% 
 
 
8.80% 
 
 
 
 
 
 
 
 
Percent Of Capital Structure Composed Of Equity
 
 
 
 
 
51.80% 
 
 
50.40% 
 
 
 
 
 
 
 
 
Rate Base
 
 
 
 
 
1,100,000,000 
 
 
1,100,000,000 
 
 
 
 
 
 
 
 
Regulatory liability
 
 
 
 
 
 
 
 
 
 
 
$ 57,000,000 
$ 55,000,000 
 
 
 
 
Percentage of Fixed non-volumetric customer charge
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
80.00% 
85.00% 
Rate And Regulatory Matters (Narrative-Federal) (Detail) (USD $)
1 Months Ended 6 Months Ended 12 Months Ended 1 Months Ended
Nov. 30, 2012
design
Jun. 30, 2013
design
Dec. 31, 2012
Jun. 30, 2013
Ameren Illinois Company [Member]
Dec. 31, 2012
Ameren Illinois Company [Member]
Jun. 30, 2013
Ameren Illinois Company [Member]
Pending Ferc Case [Member]
Minimum [Member]
Jun. 30, 2013
Ameren Illinois Company [Member]
Pending Ferc Case [Member]
Maximum [Member]
Jun. 30, 2013
Ameren Missouri [Member]
Dec. 31, 2012
Ameren Missouri [Member]
Jun. 30, 2013
Ameren Missouri [Member]
New Nuclear Energy Center COL [Member]
Dec. 31, 2012
Ameren Missouri [Member]
New Nuclear Energy Center COL [Member]
Minimum [Member]
Jun. 30, 2013
Ameren Missouri [Member]
New Nuclear Energy Center COL [Member]
Minimum [Member]
Jun. 30, 2013
Ameren Missouri [Member]
New Nuclear Energy Center COL [Member]
Maximum [Member]
Jun. 30, 2013
Wholesale Distribution Rate Case [Member]
Dec. 31, 2012
Wholesale Distribution Rate Case [Member]
Jan. 31, 2011
Wholesale Distribution Rate Case [Member]
Ameren Illinois Company [Member]
appraiser
Jun. 30, 2013
Wholesale Distribution Rate Case [Member]
Ameren Illinois Company [Member]
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of Customers, Reached Agreements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4 
 
Number of Wholesale Customers
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9 
 
Number of Customers, Remaining on Agreements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5 
 
Current regulatory liabilities
 
$ 180,000,000 
$ 100,000,000 
$ 110,000,000 
$ 82,000,000 
 
 
$ 71,000,000 
$ 18,000,000 
 
 
 
 
$ 11,000,000 
$ 8,000,000 
 
$ 9,000,000 
Range of possible loss, minimum
 
 
 
 
 
10,000,000 
15,000,000 
 
 
 
 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of years an COL is valid for
 
 
 
 
 
 
 
 
 
 
40 years 
 
 
 
 
 
 
Investments in Power and Distribution Projects
 
 
 
 
 
 
 
 
 
$ 69,000,000 
 
$ 80,000,000 
$ 100,000,000 
 
 
 
 
Short-Term Debt And Liquidity (Narrative) (Detail) (USD $)
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Line of Credit Facility [Line Items]
 
 
 
 
Commercial paper outstanding
   
 
   
 
Commercial Paper [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Commercial paper outstanding
25,000,000 
 
25,000,000 
 
Average daily commercial paper borrowings outstanding
 
 
13,000,000 
72,000,000 
Weighted average interest rate
0.54% 
0.94% 
0.54% 
0.94% 
Peak short-term borrowings
 
 
78,000,000 
229,000,000 
Peak short-term borrowings interest rate
 
 
0.85% 
1.25% 
Utilities [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Short Term Debt, Weighted Average Interest Rate During Period
0.07% 
0.14% 
0.09% 
0.12% 
Non State Regulated Subsidiaries [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Short Term Debt, Weighted Average Interest Rate During Period
0.29% 
0.64% 
0.26% 
0.70% 
Credit Agreements 2012 [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Line of credit facility, maximum borrowing capacity
$ 2,060,000,000 
 
$ 2,060,000,000 
 
Actual debt-to-capital ratio percentage
0.52 
 
0.52 
 
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
2.0 to 1 
 
Covenant terms, ratio of consolidated operational funds to consolidated interest expense, minimum
 
 
2.0 
 
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
4.9 to 1.0 
 
Covenant compliance, ratio of consolidated operational funds to consolidated interest expense
 
 
4.9 
 
Credit Agreements 2012 [Member] |
Maximum [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Actual debt-to-capital ratio percentage
0.65 
 
0.65 
 
Credit Agreements 2012 [Member] |
Ameren Missouri [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Actual debt-to-capital ratio percentage
0.48 
 
0.48 
 
Credit Agreements 2012 [Member] |
Ameren Illinois Company [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Actual debt-to-capital ratio percentage
0.42 
 
0.42 
 
Long-Term Debt And Equity Financings (Narrative) (Detail) (USD $)
6 Months Ended
Jun. 30, 2013
Long-Term Debt And Equity Financings [Line Items]
 
Excess in indebtedness upon default of maturity
$ 25,000,000 
Ameren Missouri And Ameren Illinois [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Assumed interest rate
6.00% 
Dividend rate
7.00% 
Ameren Illinois Company [Member] |
Federal Energy Regulatory Commission Restriction [Member] |
Actual Ratio [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Common stock equity to total capitalization
57.00% 
Ameren Illinois Company [Member] |
Minimum [Member] |
Federal Energy Regulatory Commission Restriction [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Common stock equity to total capitalization
30.00% 
Long-Term Debt And Equity Financings (Schedule Of Covered Ratio) (Detail) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Jun. 30, 2013
Ameren Missouri [Member]
 
Debt Instrument [Line Items]
 
Bonds Issuable
$ 3,633 1
Preferred Stock Issuable
2,118 
Retired bond capacity
485 
Ameren Missouri [Member] |
Actual Ratio [Member]
 
Debt Instrument [Line Items]
 
Restricted payment interest coverage ratio, Actual
4.4 
Dividend Coverage Ratio
110.9 
Ameren Illinois Company [Member]
 
Debt Instrument [Line Items]
 
Bonds Issuable
3,581 1 2
Preferred Stock Issuable
203 
Retired bond capacity
$ 645 
Ameren Illinois Company [Member] |
Actual Ratio [Member]
 
Debt Instrument [Line Items]
 
Restricted payment interest coverage ratio, Actual
7.3 
Dividend Coverage Ratio
2.7 
Minimum [Member] |
Ameren Missouri [Member] |
Minimum Required Ratio [Member]
 
Debt Instrument [Line Items]
 
Restricted payment interest coverage ratio, Actual
2.0 3
Dividend Coverage Ratio
2.5 4
Minimum [Member] |
Ameren Illinois Company [Member] |
Minimum Required Ratio [Member]
 
Debt Instrument [Line Items]
 
Restricted payment interest coverage ratio, Actual
2.0 3
Dividend Coverage Ratio
1.5 4
Other Income and Expenses (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Other Nonoperating Income (Expense) [Line Items]
 
 
 
 
Allowance for equity funds used during construction
$ 8 1
$ 8 1
$ 16 1
$ 17 1
Interest income on industrial development revenue bonds
7 1
7 1
14 1
14 1
Interest and dividend income
1 1
4 1
1 1
4 1
Other
0 1
0 1
0 1
1 1
Total miscellaneous income
16 1
19 1
31 1
36 1
Donations
1.0 1
3.0 1
5.0 1
15.0 1 2
Other
4 1
4 1
8 1
7 1
Total miscellaneous expense
5 1
7 1
13 1
22 1
Ameren Missouri [Member]
 
 
 
 
Other Nonoperating Income (Expense) [Line Items]
 
 
 
 
Allowance for equity funds used during construction
7 
7 
14 
15 
Interest income on industrial development revenue bonds
7 
7 
14 
14 
Interest and dividend income
0 
4 
0 
4 
Total miscellaneous income
14 
18 
28 
33 
Donations
1.0 
3.0 
3.0 
5.0 
Other
2 
1 
5 
2 
Total miscellaneous expense
3 
4 
8 
7 
Ameren Illinois [Member]
 
 
 
 
Other Nonoperating Income (Expense) [Line Items]
 
 
 
 
Allowance for equity funds used during construction
1 
1 
2 
2 
Interest and dividend income
1 
0 
1 
0 
Other
0 
1 
0 
1 
Total miscellaneous income
2 
2 
3 
3 
Donations
0 
0 
3.0 
10.0 2
Other
1 
2 
1 
3 
Total miscellaneous expense
1 
2 
4 
13 
Ameren Illinois [Member] |
One-Time Donation [Member] |
Illinois Science And Energy Innovation Trust [Member]
 
 
 
 
Other Nonoperating Income (Expense) [Line Items]
 
 
 
 
Donations
 
 
$ 7.5 
 
Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Detail)
Jun. 30, 2013
MMBTU
Dec. 31, 2012
MMBTU
Derivativea That Qualify for Regulatory Deferral [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
157,000,000 1
147,000,000 1
Derivativea That Qualify for Regulatory Deferral [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
18,000,000 1
23,000,000 1
Derivativea That Qualify for Regulatory Deferral [Member] |
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
514,000 1
446,000 1
Derivativea That Qualify for Regulatory Deferral [Member] |
Ameren Missouri [Member] |
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
58,000,000 1 2
70,000,000 1 2
Derivativea That Qualify for Regulatory Deferral [Member] |
Ameren Missouri [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
30,000,000 1
19,000,000 1
Derivativea That Qualify for Regulatory Deferral [Member] |
Ameren Missouri [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
7,000,000 1
9,000,000 1
Derivativea That Qualify for Regulatory Deferral [Member] |
Ameren Illinois Company [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
127,000,000 1
128,000,000 1
Derivativea That Qualify for Regulatory Deferral [Member] |
Ameren Illinois Company [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
11,000,000 1
14,000,000 1
Other Contract [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
   
   
Other Contract [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
1,000,000 3
2,000,000 3
Other Contract [Member] |
Ameren Missouri [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
   
   
Other Contract [Member] |
Ameren Missouri [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
1,000,000 3
2,000,000 3
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Coal [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
85,000,000 4
96,000,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
9,000,000 4
20,000,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
21,000,000 4
24,000,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Renewable Energy Credits [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
14,000,000 4 5
15,000,000 4 5
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
4,671,000 4
5,142,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Ameren Missouri [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
 
4,000,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Ameren Missouri [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
3,000,000 4
3,000,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Ameren Missouri [Member] |
Renewable Energy Credits [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
3,000,000 4 5
3,000,000 4 5
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Ameren Illinois Company [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
9,000,000 4
16,000,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Ameren Illinois Company [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
18,000,000 4
21,000,000 4
Accrual and Normal Purchases and Normal Sales Contracts [Member] |
Ameren Illinois Company [Member] |
Renewable Energy Credits [Member]
 
 
Derivative [Line Items]
 
 
Accrual & NPNS Contracts
11,000,000 4 5
12,000,000 4 5
Derivative Financial Instruments (Derivative Instruments Carrying Value) (Detail) (Not Designated As Hedging Instrument [Member], USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Derivative [Line Items]
 
 
Derivative assets
$ 57 1
$ 29 1
Derivative liabilities
183 1
230 1
Fuel Oils [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
5 1
8 1
Fuel Oils [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
2 1
4 1
Fuel Oils [Member] |
Mark To Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 1
2 1
Fuel Oils [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 1
2 1
Natural Gas [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
2 1
1 1
Natural Gas [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
1 1
Natural Gas [Member] |
Mark To Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
52 1
64 1
Natural Gas [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
33 1
45 1
Power [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
45 1
14 1
Power [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
2 1
1 1
Power [Member] |
Mark To Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
18 1
25 1
Power [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
73 1
90 1
Uranium [Member] |
Mark To Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
3 1
1 1
Uranium [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
 
1 1
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
53 1
28 1
Derivative liabilities
28 1
25 1
Ameren Missouri [Member] |
Fuel Oils [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
5 1
8 1
Ameren Missouri [Member] |
Fuel Oils [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
2 1
4 1
Ameren Missouri [Member] |
Fuel Oils [Member] |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 1
2 1
Ameren Missouri [Member] |
Fuel Oils [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 1
2 1
Ameren Missouri [Member] |
Natural Gas [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
 
Ameren Missouri [Member] |
Natural Gas [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
 
1 1
Ameren Missouri [Member] |
Natural Gas [Member] |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
7 1
8 1
Ameren Missouri [Member] |
Natural Gas [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
5 1
7 1
Ameren Missouri [Member] |
Power [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
44 1
14 1
Ameren Missouri [Member] |
Power [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
1 1
Ameren Missouri [Member] |
Power [Member] |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
8 1
4 1
Ameren Missouri [Member] |
Power [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
1 1
 
Ameren Missouri [Member] |
Uranium [Member] |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
3 1
1 1
Ameren Missouri [Member] |
Uranium [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
 
1 1
Ameren Illinois Company [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
4 1
1 1
Derivative liabilities
155 1
205 1
Ameren Illinois Company [Member] |
Natural Gas [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
1 1
Ameren Illinois Company [Member] |
Natural Gas [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
 
Ameren Illinois Company [Member] |
Natural Gas [Member] |
Mark To Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
45 1
56 1
Ameren Illinois Company [Member] |
Natural Gas [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
28 1
38 1
Ameren Illinois Company [Member] |
Power [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
 
Ameren Illinois Company [Member] |
Power [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 1
 
Ameren Illinois Company [Member] |
Power [Member] |
Mark To Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
10 1
21 1
Ameren Illinois Company [Member] |
Power [Member] |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
$ 72 1
$ 90 1
Derivative Financial Instruments (Cumulative Amount Of Pretax Net Gains (Losses) On All Derivative Instruments In OCI) (Detail) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
$ 180 
$ 100 
Current losses deferred as regulatory assets
192 
247 
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
2 
 
Current losses deferred as regulatory assets
1 
 
Fuel Oils [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
   1
4 1
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
2 
 
Current losses deferred as regulatory assets
52 
 
Natural Gas [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(83)2
(107)2
Power [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
44 
 
Current losses deferred as regulatory assets
16 
 
Power [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(43)3
(99)3
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
3 
 
Uranium [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(3)4
(2)4
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
71 
18 
Current losses deferred as regulatory assets
132 
163 
Ameren Missouri [Member] |
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
2 
 
Current losses deferred as regulatory assets
1 
 
Ameren Missouri [Member] |
Fuel Oils [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
   1
4 1
Ameren Missouri [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
1 
 
Current losses deferred as regulatory assets
7 
 
Ameren Missouri [Member] |
Natural Gas [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(12)2
(14)2
Ameren Missouri [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
43 
 
Current losses deferred as regulatory assets
6 
 
Ameren Missouri [Member] |
Power [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
37 3
12 3
Ameren Missouri [Member] |
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
3 
 
Ameren Missouri [Member] |
Uranium [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(3)4
(2)4
Ameren Illinois Company [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
110 
82 
Current losses deferred as regulatory assets
61 
84 
Ameren Illinois Company [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
1 
 
Current losses deferred as regulatory assets
45 
 
Ameren Illinois Company [Member] |
Natural Gas [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(71)2
(93)2
Ameren Illinois Company [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
1 
 
Current losses deferred as regulatory assets
10 
 
Ameren Illinois Company [Member] |
Power [Member] |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
$ (80)3
$ (111)3
Derivative Financial Instruments (Offsetting Derivative Assets and Liabilities) (Details) (Commodity Contract [Member], USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Offsetting Assets and Liabilities [Line Items]
 
 
Gross Amounts Recognized in the Balance Sheet
$ 57 1
$ 29 1
Derivative Instruments
15 
10 
Cash Collateral Received/Posted
   2
   2
Net Amount
42 
19 
Gross Amounts Recognized in the Balance Sheet
183 1
230 1
Derivative Instruments
15 
10 
Cash Collateral Received/Posted
32 2
65 2
Net Amount
136 
155 
Ameren Missouri [Member]
 
 
Offsetting Assets and Liabilities [Line Items]
 
 
Gross Amounts Recognized in the Balance Sheet
53 1
28 1
Derivative Instruments
13 
9 
Cash Collateral Received/Posted
   2
   2
Net Amount
40 
19 
Gross Amounts Recognized in the Balance Sheet
28 1
25 1
Derivative Instruments
13 
9 
Cash Collateral Received/Posted
6 2
7 2
Net Amount
9 
9 
Ameren Illinois Company [Member]
 
 
Offsetting Assets and Liabilities [Line Items]
 
 
Gross Amounts Recognized in the Balance Sheet
4 
1 
Derivative Instruments
2 
1 
Cash Collateral Received/Posted
   2
   2
Net Amount
2 
   
Gross Amounts Recognized in the Balance Sheet
155 1
205 1
Derivative Instruments
2 
1 
Cash Collateral Received/Posted
26 2
58 2
Net Amount
$ 127 
$ 146 
Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Detail) (USD $)
In Millions, unless otherwise specified
6 Months Ended 12 Months Ended
Jun. 30, 2013
Dec. 31, 2012
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
$ 31 
$ 23 
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
29 
22 
Ameren Illinois Company [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
2 
1 
Commodity Marketing Companies [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
3 
2 
Commodity Marketing Companies [Member] |
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
3 
2 
Electric Utilities [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
5 
3 
Electric Utilities [Member] |
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
5 
3 
Financial Companies [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
17 
15 
Financial Companies [Member] |
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
16 
14 
Financial Companies [Member] |
Ameren Illinois Company [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
1 
1 
Municipalities/Cooperatives [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
5 
3 
Municipalities/Cooperatives [Member] |
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
5 
3 
Oil And Gas Companies [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
1 
 
Oil And Gas Companies [Member] |
Ameren Illinois Company [Member]
 
 
Derivative [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
$ 1 
 
Derivative Financial Instruments (Narrative) (Detail) (Ameren Missouri [Member], USD $)
In Millions, unless otherwise specified
Dec. 31, 2012
Ameren Missouri [Member]
 
Derivative [Line Items]
 
Counterparty letters of credit held as collateral
$ 1 
Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Detail) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 10 
$ 15 
Ameren Missouri [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
10 
15 
Commodity Marketing Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
1 
1 
Commodity Marketing Companies [Member] |
Ameren Missouri [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
1 
1 
Electric Utilities [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
4 
1 
Electric Utilities [Member] |
Ameren Missouri [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
4 
1 
Financial Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
2 
10 
Financial Companies [Member] |
Ameren Missouri [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
2 
10 
Municipalities/Cooperatives [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
3 
3 
Municipalities/Cooperatives [Member] |
Ameren Missouri [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 3 
$ 3 
Derivative Financial Instruments (Derivatives That Qualify For Regulatory Deferral) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
$ 19 
$ 26 
$ 75 
$ (149)
Ameren Missouri [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
28 
(10)
22 
(8)
Ameren Illinois Company [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(9)
104 
53 
(56)
Fuel Oils [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(4)
(19)
(4)
(14)
Fuel Oils [Member] |
Ameren Missouri [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(4)
(19)
(4)
(14)
Natural Gas [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(12)
46 
24 
28 
Natural Gas [Member] |
Ameren Missouri [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(2)
5 
2 
3 
Natural Gas [Member] |
Ameren Illinois Company [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(10)
41 
22 
25 
Power [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
36 1
(1)1
56 1
(163)1
Power [Member] |
Ameren Missouri [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
35 
4 
25 
3 
Power [Member] |
Ameren Illinois Company [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
1 
63 
31 
(81)
Uranium [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(1)
   
(1)
   
Uranium [Member] |
Ameren Missouri [Member]
 
 
 
 
Derivative [Line Items]
 
 
 
 
Net change in market value of derivatives that qualify for regulatory deferral
$ (1)
    
$ (1)
    
Fair Value Measurements (Schedule Of Valuation Process And Unobservable Inputs) (Detail) (USD $)
In Millions, unless otherwise specified
6 Months Ended 12 Months Ended
Jun. 30, 2013
Dec. 31, 2012
Natural Gas [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
$ 2 1
 
Natural Gas [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Credit risk
3.00% 2 3
 
Natural Gas [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.22% 2 3
 
Nodal basis
(0.1)3
 
Natural Gas [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
2.00% 2 3
 
Nodal basis
0 3
 
Natural Gas [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
1.00% 2 3
 
Nodal basis
0 3
 
Natural Gas [Member] |
Option Model [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
1.00% 4
 
Nodal basis
(0.350)3
 
Natural Gas [Member] |
Option Model [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
31.00% 4
 
Nodal basis
(0.06)3
 
Natural Gas [Member] |
Option Model [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
24.00% 4
 
Nodal basis
(0.3)3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Credit risk
3.00% 2 3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.22% 2 3
 
Nodal basis
(0.1)3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
2.00% 2 3
 
Nodal basis
0 3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
1.00% 2 3
 
Nodal basis
(0.10)3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Option Model [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
   
 
Volatilities
1.00% 4
 
Nodal basis
(0.35)3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Option Model [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
   
 
Volatilities
31.00% 4
 
Nodal basis
(0.06)3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Option Model [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
   
 
Volatilities
24.00% 4
 
Nodal basis
(0.30)3
 
Natural Gas [Member] |
Ameren Missouri [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
   1
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Credit risk
3.00% 2 3
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.69% 2 3
 
Nodal basis
(0.1)3
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
2.00% 2 3
 
Nodal basis
0 3
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
1.00% 2 3
 
Nodal basis
0 3
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Option Model [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
1.00% 4
 
Nodal basis
(0.3)3
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Option Model [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
31.00% 4
 
Nodal basis
(0.27)3
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Option Model [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
27.00% 4
 
Nodal basis
(0.28)3
 
Natural Gas [Member] |
Ameren Illinois Company [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
2 1
 
Natural Gas [Member] |
Derivative Liabilities [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(1)1
 
Natural Gas [Member] |
Derivative Liabilities [Member] |
Ameren Missouri [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(1)1
 
Natural Gas [Member] |
Derivative Liabilities [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
   1
 
Fuel Oils [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
7 1
8 1
Fuel Oils [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Credit risk
 
2.00% 2 3
Fuel Oils [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
 
0.21% 4
Counterparty credit risk
0.26% 2 3
0.12% 2 3
Fuel Oils [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
 
0.60% 4
Counterparty credit risk
3.00% 2 3
1.00% 2 3
Fuel Oils [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
 
0.44% 4
Counterparty credit risk
2.00% 2 3
1.00% 2 3
Fuel Oils [Member] |
Option Model [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
8.00% 4
7.00% 4
Fuel Oils [Member] |
Option Model [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
32.00% 4
27.00% 4
Fuel Oils [Member] |
Option Model [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
20.00% 4
24.00% 4
Fuel Oils [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Credit risk
 
2.00% 2 3
Fuel Oils [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
 
0.21% 4
Counterparty credit risk
0.26% 2 3
0.12% 2 3
Fuel Oils [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
 
0.60% 4
Counterparty credit risk
3.00% 2 3
1.00% 2 3
Fuel Oils [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
 
0.44% 4
Counterparty credit risk
2.00% 2 3
1.00% 2 3
Fuel Oils [Member] |
Ameren Missouri [Member] |
Option Model [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
8.00% 4
7.00% 4
Fuel Oils [Member] |
Ameren Missouri [Member] |
Option Model [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
32.00% 4
27.00% 4
Fuel Oils [Member] |
Ameren Missouri [Member] |
Option Model [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
20.00% 4
24.00% 4
Fuel Oils [Member] |
Ameren Missouri [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
7 1
8 1
Fuel Oils [Member] |
Derivative Liabilities [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(4)1
(3)1
Fuel Oils [Member] |
Derivative Liabilities [Member] |
Ameren Missouri [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(4)1
(3)1
Power [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Credit risk
3.00% 2 3
 
Power [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.22% 2 3
0.22% 2 3
Nodal basis
(4)3
(5)3
Credit risk
 
2.00% 2 3
Average bid/ask consensus peak and offpeak pricing
25 3
22 3
Estimated auction price
(767)4
(281)4
Power [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
7.00% 2 3
1.00% 2 3
Nodal basis
(1)3
(1)3
Credit risk
 
5.00% 2 3
Average bid/ask consensus peak and offpeak pricing
49 3
47 3
Estimated auction price
1,790 4
1,851 4
Power [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
3.00% 2 3
1.00% 2 3
Nodal basis
(3)3
(3)3
Credit risk
 
5.00% 2 3
Average bid/ask consensus peak and offpeak pricing
32 3
31 3
Estimated auction price
252 4
178 4
Power [Member] |
Fundamental Energy Production Model [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
4.00% 4 5
 
Estimated future gas prices
5 4
4 4
Power [Member] |
Fundamental Energy Production Model [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
5.00% 4 5
 
Estimated future gas prices
8 4
8 4
Power [Member] |
Fundamental Energy Production Model [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
4.00% 4 5
 
Estimated future gas prices
6 4
6 4
Power [Member] |
Contract Price Allocation [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
5 4
5 4
Power [Member] |
Contract Price Allocation [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
7 4
7 4
Power [Member] |
Contract Price Allocation [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
6 4
6 4
Power [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
44 1 6
14 1 6
Power [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Credit risk
3.00% 2 3
2.00% 2 3
Power [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.22% 2 3
0.22% 2 3
Nodal basis
(4)3
(5)3
Average bid/ask consensus peak and offpeak pricing
25 3
24 3
Estimated auction price
(767)4
(281)4
Power [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
3.00% 2 3
1.00% 2 3
Nodal basis
(1)3
(1)3
Average bid/ask consensus peak and offpeak pricing
49 3
56 3
Estimated auction price
1,790 4
1,851 4
Power [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
3.00% 2 3
1.00% 2 3
Nodal basis
(2)3
(2)3
Average bid/ask consensus peak and offpeak pricing
38 3
36 3
Estimated auction price
252 4
178 4
Power [Member] |
Ameren Missouri [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
42 1 6
14 1 6
Power [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
7.00% 2 3
 
Credit risk
3.00% 2 3
5.00% 2 3
Power [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Nodal basis
(4)4
(5)4
Average bid/ask consensus peak and offpeak pricing
26 4
22 4
Power [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Nodal basis
(1)4
(1)4
Average bid/ask consensus peak and offpeak pricing
39 4
47 4
Power [Member] |
Ameren Illinois Company [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Nodal basis
(3)4
(3)4
Average bid/ask consensus peak and offpeak pricing
30 4
30 4
Power [Member] |
Ameren Illinois Company [Member] |
Fundamental Energy Production Model [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
4.00% 4 5
 
Estimated future gas prices
5 4
4 4
Power [Member] |
Ameren Illinois Company [Member] |
Fundamental Energy Production Model [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
5.00% 4 5
 
Estimated future gas prices
8 4
8 4
Power [Member] |
Ameren Illinois Company [Member] |
Fundamental Energy Production Model [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
4.00% 4 5
 
Estimated future gas prices
6 4
6 4
Power [Member] |
Ameren Illinois Company [Member] |
Contract Price Allocation [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
5 4
5 4
Power [Member] |
Ameren Illinois Company [Member] |
Contract Price Allocation [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
7 4
7 4
Power [Member] |
Ameren Illinois Company [Member] |
Contract Price Allocation [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
6 4
6 4
Power [Member] |
Ameren Illinois Company [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
2 1 6
   1 6
Power [Member] |
Derivative Liabilities [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(87)1 6
(114)1 6
Power [Member] |
Derivative Liabilities [Member] |
Ameren Missouri [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(5)1 6
(3)1 6
Power [Member] |
Derivative Liabilities [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(82)1 6
(111)1 6
Uranium [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Average bid/ask consensus pricing
40 4
43 4
Uranium [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Average bid/ask consensus pricing
44 4
46 4
Uranium [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Average bid/ask consensus pricing
40 4
44 4
Uranium [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
   1
   1
Uranium [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Minimum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Average bid/ask consensus pricing
40 4
43 4
Uranium [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Maximum [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Average bid/ask consensus pricing
44 4
46 4
Uranium [Member] |
Ameren Missouri [Member] |
Discounted Cash Flow [Member] |
Weighted Average [Member]
 
 
Fair Value Inputs [Abstract]
 
 
Average bid/ask consensus pricing
40 4
44 4
Uranium [Member] |
Ameren Missouri [Member] |
Derivative Assets [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
   1
   1
Uranium [Member] |
Derivative Liabilities [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(3)1
(2)1
Uranium [Member] |
Derivative Liabilities [Member] |
Ameren Missouri [Member]
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
$ (3)1
$ (2)1
Fair Value Measurements (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Valuation adjustments related to net derivative contracts, liabilities
$ 3 
$ 7 
Ameren Missouri [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Valuation adjustments related to net derivative contracts, liabilities
1 
1 
Ameren Illinois Company [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Valuation adjustments related to net derivative contracts, liabilities
$ 3 
$ 7 
Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Detail) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
$ 440 1
$ 406 1
Assets fair value
497 
435 
Excluded receivables, payables, and accrued income, net
2 
2 
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
440 1
406 1
Assets fair value
493 
434 
Fuel Oils [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
7 2
8 2
Natural Gas [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
 
Commodity Contracts [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
57 2
29 2
Derivative liabilities
183 2
230 2
Commodity Contracts [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
53 2
28 2
Derivative liabilities
28 2
25 2
Commodity Contracts [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
4 
1 
Derivative liabilities
155 2
205 2
Commodity Contracts [Member] |
Fuel Oils [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
7 2
12 2
Derivative liabilities
4 2
4 2
Commodity Contracts [Member] |
Fuel Oils [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
7 2
12 2
Derivative liabilities
4 2
4 2
Commodity Contracts [Member] |
Natural Gas [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 2
2 2
Derivative liabilities
85 2
109 2
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
1 2
Derivative liabilities
12 2
15 2
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
1 2
Derivative liabilities
73 2
94 2
Commodity Contracts [Member] |
Power [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
47 2
15 2
Derivative liabilities
91 2
115 2
Commodity Contracts [Member] |
Power [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
45 2
15 2
Derivative liabilities
9 2
4 2
Commodity Contracts [Member] |
Power [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
 
Derivative liabilities
82 2
111 2
Commodity Contracts [Member] |
Uranium [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
3 2
2 2
Commodity Contracts [Member] |
Uranium [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
3 2
2 2
Cash and cash equivalents [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
3 1
1 1
Cash and cash equivalents [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
3 1
1 1
Equity Securities [Member] |
U.S. large capitalization [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
294 1
264 1
Equity Securities [Member] |
U.S. large capitalization [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
294 1
264 1
Debt Securities [Member] |
Corporate bonds [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
40 1
47 1
Debt Securities [Member] |
Corporate bonds [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
40 1
47 1
Debt Securities [Member] |
Municipal bonds [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 1
Debt Securities [Member] |
Municipal bonds [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 1
Debt Securities [Member] |
US treasury and government securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
91 1
81 1
Debt Securities [Member] |
US treasury and government securities [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
91 1
81 1
Debt Securities [Member] |
Asset-backed Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
10 1
11 1
Debt Securities [Member] |
Asset-backed Securities [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
10 1
11 1
Debt Securities [Member] |
Other Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 1
Debt Securities [Member] |
Other Debt Securities [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 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
297 1
265 1
Assets fair value
297 
269 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
297 1
265 1
Assets fair value
297 
269 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
 
   
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
4 2
Derivative liabilities
5 2
8 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
4 2
Derivative liabilities
5 2
8 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   
 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member] |
Fuel Oils [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
4 2
Derivative liabilities
   2
1 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member] |
Fuel Oils [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
4 2
Derivative liabilities
   2
1 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
   2
Derivative liabilities
5 2
7 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
   2
Derivative liabilities
5 2
7 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
 
Derivative liabilities
 
   2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Cash and cash equivalents [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
3 1
1 1
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Cash and cash equivalents [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
3 1
1 1
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Equity Securities [Member] |
U.S. large capitalization [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
294 1
264 1
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) [Member] |
Equity Securities [Member] |
U.S. large capitalization [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
294 1
264 1
Significant Other Observable Inputs (Level 2) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
143 1
141 1
Assets fair value
147 
144 
Significant Other Observable Inputs (Level 2) [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
143 1
141 1
Assets fair value
147 
143 
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
4 2
3 2
Derivative liabilities
83 2
103 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
4 2
2 2
Derivative liabilities
10 2
9 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   
 
Derivative liabilities
73 2
94 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
2 2
Derivative liabilities
79 2
102 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
1 2
Derivative liabilities
6 2
8 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
1 2
Derivative liabilities
73 2
94 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Power [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 2
1 2
Derivative liabilities
4 2
1 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Power [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 2
1 2
Derivative liabilities
4 2
1 2
Significant Other Observable Inputs (Level 2) [Member] |
Commodity Contracts [Member] |
Power [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
 
   2
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Corporate bonds [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
40 1
47 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Corporate bonds [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
40 1
47 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Municipal bonds [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Municipal bonds [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
US treasury and government securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
91 1
81 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
US treasury and government securities [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
91 1
81 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Asset-backed Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
10 1
11 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Asset-backed Securities [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
10 1
11 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Other Debt Securities [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 1
Significant Other Observable Inputs (Level 2) [Member] |
Debt Securities [Member] |
Other Debt Securities [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 1
1 1
Significant Other Unobservable Inputs (Level 3) [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Assets fair value
53 
22 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Assets fair value
49 
22 
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
53 2
22 2
Derivative liabilities
95 2
119 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
49 2
22 2
Derivative liabilities
13 2
8 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
4 
 
Derivative liabilities
82 2
111 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Fuel Oils [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
7 2
8 2
Derivative liabilities
4 2
3 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Fuel Oils [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
7 2
8 2
Derivative liabilities
4 2
3 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
   2
Derivative liabilities
1 2
   2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
 
Derivative liabilities
1 2
   2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Natural Gas [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
   2
Derivative liabilities
 
   2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Power [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
44 2
14 2
Derivative liabilities
87 2
114 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Power [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
42 2
14 2
Derivative liabilities
5 2
3 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Power [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
 
Derivative liabilities
82 2
111 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Uranium [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
3 2
2 2
Significant Other Unobservable Inputs (Level 3) [Member] |
Commodity Contracts [Member] |
Uranium [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
$ 3 2
$ 2 2
Fair Value Measurements (Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level Three In The Fair Value Hierarchy) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Mar. 31, 2012
Jun. 30, 2013
Jun. 30, 2012
Fuel Oils [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
$ 5 
$ 7 
$ 3 
$ 5 
$ 3 
Included in regulatory assets/liabilities
(2)
(4)
 
(2)
(2)
Total realized and unrealized gains (losses)
(2)
(4)
 
(2)
(2)
Purchases
 
2 
 
1 
2 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales
 
(1)
 
 
(1)
Settlements
 
(1)
 
(1)
(1)
Transfers into Level 3
 
 
 
 
2 
Ending balance
3 
3 
 
3 
3 
Change in unrealized gains (losses) related to assets/liabilities held at period end
(1)
(2)
 
(1)
(1)
Uranium [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
(2)
(1)
(1)
(2)
(1)
Included in regulatory assets/liabilities
(2)
 
 
(2)
   
Total realized and unrealized gains (losses)
(2)
0 
 
(2)
0 
Settlements
1 
 
 
1 
 
Ending balance
(3)
(1)
(1)
(3)
(1)
Change in unrealized gains (losses) related to assets/liabilities held at period end
(1)
 
   
(1)
   
Natural Gas [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
2 
 
(174)
0 
(174)
Included in regulatory assets/liabilities
   
 
 
1 
(28)
Total realized and unrealized gains (losses)
   
 
 
1 
(28)
Purchases
(1)
 
 
 
 
Settlements
 
 
 
 
17 
Transfer out of Level 3
 
 
 
 
185 
Ending balance
1 
   
 
1 
   
Change in unrealized gains (losses) related to assets/liabilities held at period end
(1)
 
 
 
123 
Power [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
(79)
(82)1
81 1
(100)
81 1
Included in regulatory assets/liabilities
2 
(10)1
 
21 
(168)1
Total realized and unrealized gains (losses)
2 
(10)1
 
21 
(168)1
Purchases
40 
22 1
 
40 
22 1
Settlements
(9)
(10)1
 
(6)
(14)1
Transfers into Level 3
 
 
 
(2)
 
Transfer out of Level 3
3 
(1)1
 
4 
(2)1
Ending balance
(43)
(81)1
 
(43)
(81)1
Change in unrealized gains (losses) related to assets/liabilities held at period end
(1)
5 1
 
15 
(179)1
Ameren Missouri [Member] |
Fuel Oils [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
5 
7 
3 
5 
3 
Included in regulatory assets/liabilities
(2)
(4)
 
(2)
(2)
Total realized and unrealized gains (losses)
(2)
(4)
 
(2)
(2)
Purchases
 
2 
 
1 
2 
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales
 
(1)
 
 
(1)
Settlements
 
(1)
 
(1)
(1)
Transfers into Level 3
 
 
 
 
2 
Ending balance
3 
3 
 
3 
3 
Change in unrealized gains (losses) related to assets/liabilities held at period end
(1)
(2)
 
(1)
(1)
Ameren Missouri [Member] |
Uranium [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
(2)
(1)
(1)
(2)
(1)
Included in regulatory assets/liabilities
(2)
 
 
(2)
   
Total realized and unrealized gains (losses)
(2)
0 
 
(2)
0 
Settlements
1 
 
 
1 
 
Ending balance
(3)
(1)
(1)
(3)
(1)
Change in unrealized gains (losses) related to assets/liabilities held at period end
(1)
 
   
(1)
   
Ameren Missouri [Member] |
Natural Gas [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
0 
 
(14)
0 
(14)
Included in regulatory assets/liabilities
   
 
 
 
(2)
Total realized and unrealized gains (losses)
   
 
 
 
(2)
Purchases
(1)
 
 
(1)
 
Settlements
 
 
 
 
1 
Transfer out of Level 3
 
 
 
 
15 
Ending balance
(1)
   
 
(1)
   
Change in unrealized gains (losses) related to assets/liabilities held at period end
(1)
 
 
 
9 
Ameren Missouri [Member] |
Power [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
2 
20 
21 
11 
21 
Included in regulatory assets/liabilities
1 
(4)
 
6 
9 
Total realized and unrealized gains (losses)
1 
(4)
 
6 
9 
Purchases
40 
22 
 
40 
22 
Settlements
(9)
(11)
 
(22)
(24)
Transfers into Level 3
 
 
 
(2)
 
Transfer out of Level 3
3 
(1)
 
4 
(2)
Ending balance
37 
26 
 
37 
26 
Change in unrealized gains (losses) related to assets/liabilities held at period end
3 
(1)
 
 
3 
Ameren Illinois Company [Member] |
Natural Gas [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
2 
 
(160)
0 
(160)
Included in regulatory assets/liabilities
   
 
 
1 
(26)
Total realized and unrealized gains (losses)
0 
 
 
1 
(26)
Purchases
   
 
 
1 
 
Settlements
 
 
 
 
16 
Transfer out of Level 3
 
 
 
 
170 
Ending balance
2 
   
 
2 
   
Change in unrealized gains (losses) related to assets/liabilities held at period end
   
 
 
 
114 
Ameren Illinois Company [Member] |
Power [Member]
 
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
 
Beginning balance
(81)
(284)
(140)
(111)
(140)
Included in regulatory assets/liabilities
1 
(1)
 
15 
(221)
Total realized and unrealized gains (losses)
1 
(1)
 
15 
(221)
Purchases
 
 
 
 
   
Settlements
   
64 
 
16 
140 
Transfer out of Level 3
 
 
   
   
   
Ending balance
(80)
(221)
(284)
(80)
(221)
Change in unrealized gains (losses) related to assets/liabilities held at period end
$ (4)
$ (6)
 
$ 15 
$ (195)2
Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Mar. 31, 2012
Jun. 30, 2013
Jun. 30, 2012
Derivative [Line Items]
 
 
 
 
 
Net fair value of Level 3 transfers
$ 3 
$ (1)
 
$ 2 
$ 185 
Fuel Oils [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
 
 
 
 
(2)
Fuel Oils [Member] |
Transfer Into/Out of Level 1 [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
   
 
   
   
2 
Natural Gas [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers out of Level 3
 
 
 
 
185 
Natural Gas [Member] |
Transfer Into/Out of Level 2 [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers out of Level 3
   
 
   
   
185 
Power [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
 
 
 
2 
 
Assets Transfers out of Level 3
3 
(1)1
 
4 
(2)1
Power [Member] |
Transfer Into/Out of Level 2 [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
   
 
   
(2)
   
Assets Transfers out of Level 3
3 
(1)
 
4 
(2)
Ameren Missouri [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Net fair value of Level 3 transfers
3 
(1)
 
2 
15 
Ameren Missouri [Member] |
Fuel Oils [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
 
 
 
 
(2)
Ameren Missouri [Member] |
Fuel Oils [Member] |
Transfer Into/Out of Level 1 [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
   
 
   
   
2 
Ameren Missouri [Member] |
Natural Gas [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers out of Level 3
 
 
 
 
15 
Ameren Missouri [Member] |
Natural Gas [Member] |
Transfer Into/Out of Level 2 [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers out of Level 3
   
 
   
   
15 
Ameren Missouri [Member] |
Power [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
 
 
 
2 
 
Assets Transfers out of Level 3
3 
(1)
 
4 
(2)
Ameren Missouri [Member] |
Power [Member] |
Transfer Into/Out of Level 2 [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers into Level 3
   
 
   
(2)
   
Assets Transfers out of Level 3
3 
(1)
 
4 
(2)
Ameren Illinois Company [Member] |
Natural Gas [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers out of Level 3
 
 
 
 
170 
Ameren Illinois Company [Member] |
Natural Gas [Member] |
Transfer Into/Out of Level 2 [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers out of Level 3
   
 
   
   
170 
Ameren Illinois Company [Member] |
Power [Member]
 
 
 
 
 
Derivative [Line Items]
 
 
 
 
 
Assets Transfers out of Level 3
 
 
   
   
   
Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Detail) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Dec. 31, 2012
Fair Value [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
$ 6,864 1 2
$ 7,110 1 2
Preferred stock
124 1 2
123 1 2
Fair Value [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
4,470 
4,625 
Preferred stock
75 
73 
Fair Value [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
1,940 
2,020 
Preferred stock
49 
49 
Carrying Amount [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
6,158 1 2
6,157 1 2
Preferred stock
142 1 2
142 1 2
Carrying Amount [Member] |
Ameren Missouri [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
4,006 
4,006 
Preferred stock
80 
80 
Carrying Amount [Member] |
Ameren Illinois Company [Member]
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
1,727 
1,727 
Preferred stock
$ 62 
$ 62 
Related Party Transactions (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended 0 Months Ended 3 Months Ended 6 Months Ended 3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2013
Ameren Illinois Company [Member]
Jun. 30, 2012
Ameren Illinois Company [Member]
Jun. 30, 2013
Ameren Illinois Company [Member]
Jun. 30, 2012
Ameren Illinois Company [Member]
Jun. 30, 2013
Ameren Missouri [Member]
Jun. 30, 2012
Ameren Missouri [Member]
Jun. 30, 2013
Ameren Missouri [Member]
Jun. 30, 2012
Ameren Missouri [Member]
Jun. 30, 2013
Medina Valley Energy Center [Member]
Jun. 30, 2013
Futures Commission Merchants [Member]
Jun. 30, 2013
Ameren Energy Marketing Company [Member]
Jun. 30, 2013
Ameren Energy Marketing Company [Member]
Ameren Illinois Company [Member]
Jun. 30, 2013
Related Party One [Member]
Ameren Illinois Company [Member]
Jun. 30, 2012
Related Party One [Member]
Ameren Illinois Company [Member]
Jun. 30, 2013
Related Party One [Member]
Ameren Illinois Company [Member]
Jun. 30, 2012
Related Party One [Member]
Ameren Illinois Company [Member]
Jun. 30, 2013
Related Party One [Member]
Ameren Missouri [Member]
Jun. 30, 2012
Related Party One [Member]
Ameren Missouri [Member]
Jun. 30, 2013
Related Party One [Member]
Ameren Missouri [Member]
Jun. 30, 2012
Related Party One [Member]
Ameren Missouri [Member]
Jun. 30, 2013
Guarantee Type, Other [Member]
Mar. 14, 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]
Jun. 30, 2013
Miscellaneous Support Services [Member]
Related Party One [Member]
Ameren Illinois Company [Member]
Jun. 30, 2013
Miscellaneous Support Services [Member]
Related Party One [Member]
Ameren Illinois Company [Member]
Jun. 30, 2012
Miscellaneous Support Services [Member]
Related Party One [Member]
Ameren Missouri [Member]
Jun. 30, 2012
Miscellaneous Support Services [Member]
Related Party One [Member]
Ameren Missouri [Member]
Related Party Transaction [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proceeds from sale of property, plant, and equipment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 100 
 
 
 
 
 
Accounts payable, related parties
 
 
 
 
 
 
 
 
 
 
 
 
10 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchase of receivables from Marketing Company
 
 
 
 
 
 
 
 
 
 
 
 
38 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Purchases of Financing Receivable, Discount
 
 
 
 
 
 
 
 
 
 
 
 
1 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transaction, Guarantees Outstanding
230 
 
 
 
 
 
 
 
 
33 
25 
166 
 
 
 
 
 
 
 
 
 
6 
 
 
 
 
 
 
Related Party Transaction, Guarantees, Maximum Exposure
 
 
 
 
 
 
 
 
 
 
 
29 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of Credit Outstanding, Amount
14 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation to provide credit support, period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24 months 
 
 
 
 
Buyer's indemnification guarantee obligation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25 
 
 
 
 
Buyer's indemnification guarantee obligation, period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24 months 
 
 
 
 
Revenue from Related Parties
 
$ 2.0 
    
$ 2.0 
    
    
$ 1.0 
    
$ 1.0 
 
 
 
 
$ 7.0 
$ 3.0 
$ 13.0 
$ 5.0 
$ 5.0 
$ 5.0 
$ 12.0 
$ 9.0 
 
 
 
$ 2.0 
$ 2.0 
$ 1.0 
$ 1.0 
Commitments And Contingencies (Callaway Energy Center) (Detail) (USD $)
6 Months Ended 6 Months Ended 0 Months Ended 6 Months Ended
Jun. 30, 2013
Week
Jun. 30, 2013
Replacement Power - Nuclear Electric Insurance Ltd [Member]
Jun. 30, 2013
Replacement Power - Energy Risk Assurance Company [Member]
Jun. 30, 2013
Public Liability And Nuclear Worker Liability - American Nuclear Insurers [Member]
Jun. 30, 2013
Public Liability And Nuclear Worker Liability - Pool Participation [Member]
Jun. 30, 2013
Property Damage - Nuclear Electric Insurance Ltd [Member]
Jul. 2, 2013
Property Damage - Nuclear Electric Insurance Ltd [Member]
Subsequent Event [Member]
Jun. 30, 2013
Property Damage European Mutual Association for Nuclear Insurance [Member]
Commitments And Contingencies [Line Items]
 
 
 
 
 
 
 
 
Maximum Coverages
$ 12,594,000,000 1
$ 490,000,000 2
$ 64,000,000 3
$ 375,000,000 
$ 12,219,000,000 4
$ 2,750,000,000 5
 
 
Maximum Assessments for Single Incidents
118,000,000 
9,000,000 6
 
 
118,000,000 7
23,000,000 
 
 
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
17,500,000.0 
 
 
 
 
 
 
 
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act
118,000,000 
 
 
 
 
 
 
 
Maximum annual payment in calendar year per reactor incident under Price Andersen Liability Provisions of Atomic Energy Act
17,500,000.0 
 
 
 
 
 
 
 
Amount of primary property liability coverage
500,000,000 
 
 
 
 
500,000,000 
 
500,000,000 
Amount of coverage in excess of primary property liability coverage
2,250,000,000.00 
 
 
 
 
 
 
 
Losses in excess of primary coverage
500,000,000 
 
 
 
 
 
 
 
Sub-limit for non-nuclear events
1,700,000,000 
 
 
 
 
1,500,000,000.0 
200,000,000 
 
Amount of weekly indemnity coverage commencing eight weeks after power outage
4,500,000.0 
 
 
 
 
 
 
 
Number of weeks of coverage after the first eight weeks of an outage
52 
 
 
 
 
 
 
 
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
71 
 
 
 
 
 
 
 
Amount of weekly indemnity coverage thereafter not exceeding policy limit
 
490,000,000 
3,600,000 
 
 
 
 
 
Sub-limit of for non-nuclear events
 
327,600,000 
 
 
 
 
 
 
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 
 
 
 
 
 
 
 
[5] First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-radiation events. Effective July 1, 2013, an additional non-radiation limit of $200 million in excess of the $1.5 billion was made available. This additional coverage is a shared limit with other generators purchasing this coverage and includes one free reinstatement. Effective August 1, 2013, $500 million in excess of the $2.25 billion property coverage and $1.7 billion non-radiation coverage was provided by European Mutual Association for Nuclear Insurance. Concurrently, the Nuclear Electric Insurance Ltd. property limit for nuclear events was reduced by $500 million.
Commitments And Contingencies (Other Obligations) (Detail) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Commitments And Contingencies [Line Items]
 
Unrecorded Unconditional Purchase Obligation
$ 7,190 
Unrecognized tax benefits
193 
Ameren Missouri [Member]
 
Commitments And Contingencies [Line Items]
 
Unrecorded Unconditional Purchase Obligation
5,026 
Unrecognized tax benefits
127 
Ameren Illinois Company [Member]
 
Commitments And Contingencies [Line Items]
 
Unrecorded Unconditional Purchase Obligation
2,122 
Unrecognized tax benefits
$ 4 
Commitments And Contingencies (Environmental Matters) (Detail) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Jun. 30, 2013
State
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
$ 395 1
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
480 1
Estimated Capital Costs 2012 [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
35 1
Estimated Capital Costs 2014 to 2017 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
120 1
Estimated Capital Costs 2014 to 2017 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
150 1
Estimated Capital Costs 2018 to 2022 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
240 1
Estimated Capital Costs 2018 to 2022 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
295 1
Ameren Energy Generating Company [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
350 2
Ameren Energy Generating Company [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
425 2
Ameren Energy Generating Company [Member] |
Estimated Capital Costs 2012 [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
30 2
Ameren Energy Generating Company [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
100 2
Ameren Energy Generating Company [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
125 2
Ameren Energy Generating Company [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
220 2
Ameren Energy Generating Company [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
270 2
Ameren Missouri [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
1,115 3
Ameren Missouri [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
1,340 3
Ameren Missouri [Member] |
Estimated Capital Costs 2012 [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
105 3
Ameren Missouri [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
215 3
Ameren Missouri [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
260 3
Ameren Missouri [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
795 3
Ameren Missouri [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
975 3
AERG [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
45 
AERG [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
55 
AERG [Member] |
Estimated Capital Costs 2012 [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
5 
AERG [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
20 
AERG [Member] |
Estimated Capital Costs 2014 to 2017 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
25 
AERG [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Minimum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
20 
AERG [Member] |
Estimated Capital Costs 2018 to 2022 [Member] |
Maximum [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state environmental regulations
25 
CAIR [Member]
 
Loss Contingencies [Line Items]
 
Number of states participating in the cap-and-trade program
28 
MATS [Member]
 
Loss Contingencies [Line Items]
 
Percent of top performing facilities
12.00% 
Former Coal Tar Distillery [Member] |
Ameren Missouri [Member]
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
2.0 
Range of possible loss maximum
5.0 
Accrual for environmental loss contingencies
2.0 
Former Coal Ash Landfill [Member] |
Ameren Illinois Company [Member]
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
0.5 
Range of possible loss maximum
6.0 
Accrual for environmental loss contingencies
0.5 
Newton Energy Center Scrubbers [Member] |
Ameren Energy Generating Company [Member] |
Newton Energy Center Estimated Capital Costs 2013 to 2017 [Member]
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
20 
Manufactured Gas Plant [Member]
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
256.0 
Range of possible loss maximum
339.0 
Accrual for environmental loss contingencies
256.0 4
Manufactured Gas Plant [Member] |
Ameren Missouri [Member]
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
5.0 
Range of possible loss maximum
6.0 
Accrual for environmental loss contingencies
5.0 4
Manufactured Gas Plant [Member] |
Ameren Illinois Company [Member]
 
Loss Contingencies [Line Items]
 
Number of remediation sites
44 
Range of possible loss, minimum
251.0 
Range of possible loss maximum
333.0 
Accrual for environmental loss contingencies
251.0 4
Other Environmental [Member] |
Ameren Illinois Company [Member]
 
Loss Contingencies [Line Items]
 
Accrual for environmental loss contingencies
0.8 
Sauget Area Two [Member] |
Ameren Missouri [Member]
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
0.3 
Range of possible loss maximum
10.0 
Accrual for environmental loss contingencies
0.3 
Substation in St Charles, Missouri [Member] |
Ameren Missouri [Member]
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
1.7 
Range of possible loss maximum
4.5 
Accrual for environmental loss contingencies
$ 1.7 
Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Detail) (Ameren Missouri [Member], USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Ameren Missouri [Member]
 
Loss Contingencies [Line Items]
 
Insurance settlements receivable
$ 68 
Commitments And Contingencies (Asset Sale) (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended 6 Months Ended
Jun. 30, 2013
Dec. 31, 2012
Feb. 29, 2012
Medina Valley Energy Center [Member]
Jun. 30, 2013
Medina Valley Energy Center [Member]
Loss Contingencies [Line Items]
 
 
 
 
Proceeds from sale of property, plant, and equipment
 
 
$ 16 
 
Nontrade Receivables
 
 
1 
 
Pretax gain from asset sale
 
 
10 
 
Receivable, charge-offs
 
 
 
1 
Current liabilities of discontinued operations
$ 1,183 
$ 1,166 
 
 
Callaway Energy Center (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended 6 Months Ended 12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Jun. 30, 2013
Nuclear Plant [Member]
mill
Dec. 31, 2012
Nuclear Plant [Member]
Nuclear Waste Matters [Line Items]
 
 
 
 
Number of mills charged for NWF fee
 
 
1 
 
Settlement payment
 
 
$ 6 
 
Assumed life of plant, in years
 
 
40 years 
 
Annual decommissioning costs included in costs of service
$ 7 
$ 7 
 
$ 7 
Missouri Public Service Commission, Requirement to file updated cost study and funding analysis for decommissioning energy center, Period
 
 
3 years 
 
Retirement Benefits (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
Defined benefit plan, estimated future employer contributions in each of the next five years
$ 500 
Minimum [Member]
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
Defined benefit plan, estimated future employer contributions in each of the next five years
50 
Maximum [Member]
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
Defined benefit plan, estimated future employer contributions in each of the next five years
$ 150 
Retirement Benefits (Components Of Net Periodic Benefit Cost) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Pension Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Service cost
$ 22 
$ 20 
$ 46 
$ 41 
Interest cost
41 
41 
81 
83 
Expected return on plan assets
(54)
(52)
(108)
(104)
Prior service cost (benefit)
(1)
(1)
(2)
(2)
Actuarial loss
24 
18 
46 
37 
Net periodic benefit cost
32 1
26 1
63 1
55 1
Postretirement Benefit Costs [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Service cost
5 
5 
11 
11 
Interest cost
11 
11 
23 
24 
Expected return on plan assets
(15)
(14)
(31)
(28)
Prior service cost (benefit)
(1)
(1)
(2)
(2)
Actuarial loss
2 
(1)
4 
2 
Net periodic benefit cost
$ 2 1
    1
$ 5 1
$ 7 1
Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Pension Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
$ 32 1
$ 26 1
$ 63 1
$ 55 1
Pension Benefit [Member] |
Ameren Missouri [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
18 
16 
36 
32 
Pension Benefit [Member] |
Ameren Illinois Company [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
11 
8 
21 
18 
Pension Benefit [Member] |
Other [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
3 
2 
6 
5 
Postretirement Benefits [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
2 1
   1
5 1
7 1
Postretirement Benefits [Member] |
Ameren Missouri [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
2 
   
5 
5 
Postretirement Benefits [Member] |
Ameren Illinois Company [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
(1)
   
   
2 
Postretirement Benefits [Member] |
Other [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
$ 1 
    
    
    
Segment Information (Narrative) (Detail)
6 Months Ended
Jun. 30, 2013
Segment
Segment Reporting [Abstract]
 
Number of reportable segments
3 
Segment Information (Schedule Of Segment Reporting Information By Segment) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 6 Months Ended
Jun. 30, 2013
Jun. 30, 2012
Jun. 30, 2013
Jun. 30, 2012
Dec. 31, 2012
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
$ 1,403 
$ 1,402 
$ 2,878 
$ 2,814 
 
Continuing Operations
105 
161 
159 
198 
 
Total assets
22,276 
 
22,276 
 
22,209 
Ameren Missouri [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
883 
838 
1,672 
1,524 
 
Intersegment revenues
6 
6 
13 
11 
 
Continuing Operations
84 
143 
124 
164 
 
Total assets
13,131 
 
13,131 
 
13,043 
Ameren Illinois Company [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
514 
564 
1,197 
1,288 
 
Intersegment revenues
2 
   
3 
   
 
Continuing Operations
31 
32 
62 
59 
 
Total assets
7,366 
 
7,366 
 
7,282 
Other Segment [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
6 
   
9 
2 
 
Intersegment revenues
   
1 
1 
2 
 
Continuing Operations
(10)
(14)
(27)
(25)
 
Total assets
1,354 
 
1,354 
 
1,228 
Intersegment Elimination [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
   
   
   
   
 
Intersegment revenues
(8)
(7)
(17)
(13)
 
Continuing Operations
   
 
   
   
 
Total assets
(1,061)
 
(1,061)
 
(944)
Segment, Continuing Operations [Member]
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
1,403 
1,402 
2,878 
2,814 
 
Continuing Operations
105 
161 
159 
198 
 
Total assets
$ 20,790 1
 
$ 20,790 1
 
$ 20,609 1