AMEREN ILLINOIS CO, 10-Q filed on 11/10/2014
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2014
Entity Information [Line Items]
 
Document Type
10-Q 
Amendment Flag
false 
Document Period End Date
Sep. 30, 2014 
Document Fiscal Year Focus
2014 
Document Fiscal Period Focus
Q3 
Trading Symbol
AEE 
Entity Registrant Name
AMEREN CORP 
Entity Central Index Key
0001002910 
Current Fiscal Year End Date
--12-31 
Entity Filer Category
Large Accelerated Filer 
Entity Common Stock, Shares Outstanding
242,634,798 
Union Electric Company
 
Entity Information [Line Items]
 
Document Type
10-Q 
Amendment Flag
false 
Document Period End Date
Sep. 30, 2014 
Document Fiscal Year Focus
2014 
Document Fiscal Period Focus
Q3 
Entity Registrant Name
UNION ELECTRIC CO 
Entity Central Index Key
0000100826 
Current Fiscal Year End Date
--12-31 
Entity Filer Category
Non-accelerated Filer 
Entity Common Stock, Shares Outstanding
102,123,834 
Ameren Illinois Company
 
Entity Information [Line Items]
 
Document Type
10-Q 
Amendment Flag
false 
Document Period End Date
Sep. 30, 2014 
Document Fiscal Year Focus
2014 
Document Fiscal Period Focus
Q3 
Entity Registrant Name
AMEREN ILLINOIS CO 
Entity Central Index Key
0000018654 
Current Fiscal Year End Date
--12-31 
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 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Operating Revenues:
 
 
 
 
Electric
$ 1,523 
$ 1,507 
$ 3,864 
$ 3,823 
Gas
147 
131 
819 
693 
Total operating revenues
1,670 
1,638 
4,683 
4,516 
Operating Expenses:
 
 
 
 
Fuel
236 
222 
638 
648 
Purchased power
112 
128 
335 
400 
Gas purchased for resale
49 
42 
432 
344 
Other operations and maintenance
404 
383 
1,236 
1,229 
Depreciation and amortization
187 
175 
551 
528 
Taxes other than income taxes
121 
121 
362 
354 
Total operating expenses
1,109 
1,071 
3,554 
3,503 
Operating Income
561 
567 
1,129 
1,013 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
21 1
20 1
60 1
51 1
Miscellaneous expense
7 1
5 1
20 1
18 1
Total other income (expense)
14 
15 
40 
33 
Interest Charges
85 
88 
266 
289 
Income Before Income Taxes
490 
494 
903 
757 
Income Taxes
194 
187 
357 
288 
Income from Continuing Operations
296 
307 
546 
469 
Loss from Discontinued Operations, Net of Taxes (Note 12)
(1)
(3)
(3)
(212)
Net Income (Loss)
295 
304 
543 
257 
Pension and other postretirement benefit plan activity, net of income taxes (benefit)
   
(5)
3 
5 
Comprehensive Income
293 
292 
541 
241 
Less: Net Income (Loss) Attributable to Noncontrolling Interests:
 
 
 
 
Net Income from Continuing Operations Attributable to Noncontrolling Interests
2 
2 
5 
5 
Net Income (Loss):
 
 
 
 
Continuing Operations
294 
305 
541 
464 
Discontinued Operations
(1)
(3)
(3)
(212)
Net Income (Loss)
293 
302 
538 
252 
Earnings Per Share, Basic [Abstract]
 
 
 
 
Continuing Operations
$ 1.21 
$ 1.26 
$ 2.23 
$ 1.92 
Discontinued Operations
   
$ (0.01)
$ (0.01)
$ (0.88)
Earnings Per Share, Basic
$ 1.21 
$ 1.25 
$ 2.22 
$ 1.04 
Earnings Per Share, Diluted [Abstract]
 
 
 
 
Continuing Operations
$ 1.20 
$ 1.25 
$ 2.21 
$ 1.91 
Discontinued Operations
   
$ (0.01)
$ (0.01)
$ (0.88)
Earnings Per Share, Diluted
$ 1.20 
$ 1.24 
$ 2.20 
$ 1.03 
Dividends per Common Share
$ 0.40 
$ 0.40 
$ 1.20 
$ 1.20 
Average Common Shares Outstanding - Basic
242.6 
242.6 
242.6 
242.6 
Average Common Shares Outstanding - Diluted
244.3 
245.1 
244.3 
244.4 
Union Electric Company
 
 
 
 
Operating Revenues:
 
 
 
 
Electric
1,076 
1,075 
2,696 
2,667 
Gas
21 
17 
117 
110 
Other
   
1 
1 
1 
Total operating revenues
1,097 
1,093 
2,814 
2,778 
Operating Expenses:
 
 
 
 
Fuel
236 
222 
638 
648 
Purchased power
25 
33 
86 
100 
Gas purchased for resale
7 
4 
58 
52 
Other operations and maintenance
228 
212 
677 
686 
Depreciation and amortization
118 
114 
351 
338 
Taxes other than income taxes
89 
91 
248 
247 
Total operating expenses
703 
676 
2,058 
2,071 
Operating Income
394 
417 
756 
707 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
15 
16 
45 
44 
Miscellaneous expense
4 
2 
10 
10 
Total other income (expense)
11 
14 
35 
34 
Interest Charges
53 
43 
159 
159 
Income Before Income Taxes
352 
388 
632 
582 
Income Taxes
129 
149 
234 
217 
Net Income (Loss)
223 
239 
398 
365 
Other Comprehensive Income
0 
0 
0 
0 
Comprehensive Income
223 
239 
398 
365 
Net Income (Loss):
 
 
 
 
Net Income (Loss)
223 
239 
398 
365 
Earnings Per Share, Diluted [Abstract]
 
 
 
 
Preferred Stock Dividends
1 
1 
3 
3 
Net Income Available to Common Stockholder
222 
238 
395 
362 
Ameren Illinois Company
 
 
 
 
Operating Revenues:
 
 
 
 
Electric
445 
432 
1,162 
1,160 
Gas
127 
115 
703 
585 
Other
   
   
   
2 
Total operating revenues
572 
547 
1,865 
1,747 
Operating Expenses:
 
 
 
 
Purchased power
89 
96 
256 
303 
Gas purchased for resale
43 
38 
374 
292 
Other operations and maintenance
185 
166 
580 
538 
Depreciation and amortization
66 
59 
193 
182 
Taxes other than income taxes
31 
30 
109 
102 
Total operating expenses
414 
389 
1,512 
1,417 
Operating Income
158 
158 
353 
330 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
4 
4 
12 
7 
Miscellaneous expense
2 
3 
7 
7 
Total other income (expense)
2 
1 
5 
0 
Interest Charges
31 
31 
90 
96 
Income Before Income Taxes
129 
128 
268 
234 
Income Taxes
54 
51 
110 
93 
Net Income (Loss)
75 
77 
158 
141 
Pension and other postretirement benefit plan activity, net of income taxes (benefit)
   
   
(2)
(2)
Comprehensive Income
75 
77 
156 
139 
Net Income (Loss):
 
 
 
 
Net Income (Loss)
75 
77 
158 
141 
Earnings Per Share, Diluted [Abstract]
 
 
 
 
Preferred Stock Dividends
   
   
2 
2 
Net Income Available to Common Stockholder
$ 75 
$ 77 
$ 156 
$ 139 
Consolidated Statement of Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Pension and other postretirement benefit plan activity, tax expense (benefit)
    
$ (5)
$ 3 
$ 3 
Ameren Illinois Company
 
 
 
 
Pension and other postretirement benefit plan activity, tax expense (benefit)
$ (1)
$ (1)
$ (2)
$ (2)
Consolidated Statement of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Income from Continuing Operations
$ 296 
$ 307 
$ 546 
$ 469 
Other Comprehensive Income (Loss), Net of Taxes
 
 
 
 
Pension and other postretirement benefit plan activity, net of income taxes (benefit)
   
(5)
3 
5 
Comprehensive Income from Continuing Operations
296 
302 
549 
474 
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests
2 
2 
5 
5 
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation
294 
300 
544 
469 
Loss from Discontinued Operations, Net of Taxes
(1)
(3)
(3)
(212)
Other Comprehensive Loss from Discontinued Operations, Net of Taxes
   
(5)
   
(16)
Comprehensive Loss from Discontinued Operations Attributable to Ameren Corporation
(1)
(8)
(3)
(228)
Comprehensive Income
$ 293 
$ 292 
$ 541 
$ 241 
Consolidated Statement of Comprehensive Income (Loss) Consolidated Statement of Income (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
 
 
 
 
Pension and other postretirement benefit plan activity, tax expense (benefit)
    
$ (5)
$ 3 
$ 3 
Consolidated Balance Sheet (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Current Assets:
 
 
Cash and cash equivalents
$ 13 
$ 30 
Accounts receivable - trade (less allowance for doubtful accounts)
467 
404 
Unbilled revenue
203 
304 
Miscellaneous accounts and notes receivable
117 
196 
Materials and supplies
561 
526 
Current regulatory assets
199 
156 
Current accumulated deferred income taxes, net
301 
106 
Other current assets
66 
85 
Assets of discontinued operations (Note 12)
15 
165 
Total current assets
1,942 
1,972 
Property and Plant, Net
16,991 
16,205 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
529 
494 
Goodwill
411 
411 
Intangible assets
20 
22 
Regulatory assets
1,259 
1,240 
Other assets
724 
698 
Total investments and other assets
2,943 
2,865 
TOTAL ASSETS
21,876 
21,042 
Current Liabilities:
 
 
Current maturities of long-term debt
119 
534 
Short-term Debt
753 
368 
Accounts and wages payable
466 
806 
Taxes accrued
161 
55 
Interest accrued
105 
86 
Current regulatory liabilities
132 
216 
Other current liabilities
350 
351 
Liabilities of discontinued operations (Note 12)
33 
45 
Total current liabilities
2,119 
2,461 
Long-term Debt, Net
5,825 
5,504 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
3,845 
3,250 
Accumulated deferred investment tax credits
59 
63 
Regulatory liabilities
1,805 
1,705 
Asset retirement obligations
385 
369 
Pension and other postretirement benefits
400 
466 
Other deferred credits and liabilities
522 
538 
Total deferred credits and other liabilities
7,016 
6,391 
Commitments and Contingencies
   
   
Stockholders' Equity:
 
 
Common Stock
2 
2 
Other paid-in capital
5,612 
5,632 
Retained earnings
1,154 
907 
Accumulated other comprehensive income (loss)
6 
3 
Stockholder's equity
6,774 
6,544 
Noncontrolling Interest
142 1
142 
Total equity
6,916 
6,686 
TOTAL LIABILITIES AND EQUITY
21,876 
21,042 
Union Electric Company
 
 
Current Assets:
 
 
Cash and cash equivalents
1 
1 
Accounts receivable - trade (less allowance for doubtful accounts)
261 
191 
Accounts receivable - affiliates
12 
1 
Unbilled revenue
134 
168 
Miscellaneous accounts and notes receivable
86 
57 
Materials and supplies
350 
352 
Current regulatory assets
137 
118 
Other current assets
40 
71 
Total current assets
1,021 
959 
Property and Plant, Net
10,660 
10,452 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
529 
494 
Intangible assets
20 
22 
Regulatory assets
539 
534 
Other assets
410 
443 
Total investments and other assets
1,498 
1,493 
TOTAL ASSETS
13,179 
12,904 
Current Liabilities:
 
 
Current maturities of long-term debt
119 
109 
Borrowings from money pool
   
105 
Short-term Debt
65 
   
Accounts and wages payable
189 
387 
Accounts payable - affiliates
32 
30 
Taxes accrued
200 
220 
Interest accrued
66 
57 
Current regulatory liabilities
11 
57 
Other current liabilities
99 
82 
Total current liabilities
781 
1,047 
Long-term Debt, Net
3,885 
3,648 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
2,656 
2,524 
Accumulated deferred investment tax credits
55 
59 
Regulatory liabilities
1,107 
1,041 
Asset retirement obligations
383 
366 
Pension and other postretirement benefits
147 
189 
Other deferred credits and liabilities
44 
37 
Total deferred credits and other liabilities
4,392 
4,216 
Commitments and Contingencies
   
   
Stockholders' Equity:
 
 
Common Stock
511 
511 
Other paid-in capital
1,560 
1,560 
Preferred stock not subject to mandatory redemption
80 
80 
Retained earnings
1,970 
1,842 
Stockholder's equity
4,121 
3,993 
TOTAL LIABILITIES AND EQUITY
13,179 
12,904 
Ameren Illinois Company
 
 
Current Assets:
 
 
Cash and cash equivalents
1 
1 
Accounts receivable - trade (less allowance for doubtful accounts)
192 
201 
Accounts receivable - affiliates
2 
   
Unbilled revenue
69 
135 
Miscellaneous accounts and notes receivable
6 
13 
Materials and supplies
211 
174 
Current regulatory assets
62 
38 
Current accumulated deferred income taxes, net
125 
45 
Other current assets
17 
26 
Total current assets
685 
633 
Property and Plant, Net
6,030 
5,589 
Investments and Other Assets:
 
 
Goodwill
411 
411 
Regulatory assets
712 
701 
Other assets
145 
120 
Total investments and other assets
1,268 
1,232 
TOTAL ASSETS
7,983 
7,454 
Current Liabilities:
 
 
Borrowings from money pool
16 
56 
Short-term Debt
189 
   
Accounts and wages payable
212 
243 
Accounts payable - affiliates
28 
18 
Taxes accrued
16 
23 
Customer deposits
71 
79 
Current environmental remediation
53 
43 
Current regulatory liabilities
121 
159 
Other current liabilities
148 
150 
Total current liabilities
854 
771 
Long-term Debt, Net
1,940 
1,856 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
1,330 
1,116 
Accumulated deferred investment tax credits
3 
4 
Regulatory liabilities
698 
664 
Pension and other postretirement benefits
189 
197 
Environmental remediation
202 
232 
Other deferred credits and liabilities
165 
166 
Total deferred credits and other liabilities
2,587 
2,379 
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
566 
410 
Accumulated other comprehensive income (loss)
9 
11 
Stockholder's equity
2,602 
2,448 
TOTAL LIABILITIES AND EQUITY
$ 7,983 
$ 7,454 
Consolidated Balance Sheet (Parenthetical) (USD $)
In Millions, except Per Share data, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Accounts receivable - trade allowance for doubtful accounts
$ 21 
$ 18 
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
 
 
Accounts receivable - trade allowance for doubtful accounts
7 
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
 
 
Accounts receivable - trade allowance for doubtful accounts
$ 14 
$ 13 
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
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Cash Flows From Operating Activities:
 
 
Net income (loss)
$ 543 
$ 257 
Loss from discontinued operations, net of taxes
3 
212 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
526 
500 
Amortization of nuclear fuel
70 
46 
Amortization of debt issuance costs and premium/discounts
16 
18 
Deferred income taxes and investment tax credits, net
370 
258 
Allowance for equity funds used during construction
(26)1
(26)1
Stock-based compensation costs
20 
19 
Other
(9)
14 
Changes in assets and liabilities:
 
 
Receivables
16 
(88)
Materials and supplies
(34)
7 
Accounts and wages payable
(187)
(102)
Taxes accrued
100 
104 
Assets, other
(123)
20 
Liabilities, other
(70)
(24)
Pension and other postretirement benefits
(27)
(34)
Counterparty collateral, net
20 
34 
Net cash provided by operating activities – continuing operations
1,208 
1,215 
Net cash provided by (used in) operating activities – discontinued operations
(5)
99 
Net cash provided by operating activities
1,203 
1,314 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(1,310)
(943)
Nuclear fuel expenditures
(28)
(34)
Purchases of securities - nuclear decommissioning trust fund
(365)
(147)
Sales and maturities of securities - nuclear decommissioning trust fund
354 
134 
Proceeds from Notes Receivable
79 
   
Contributions to Note Receivable
(84)
   
Other
3 
(1)
Net cash used in investing activities – continuing operations
(1,351)
(991)
Net cash provided by (used in) investing activities – discontinued operations
139 
(42)
Net cash used in investing activities
(1,212)
(1,033)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(291)
(291)
Dividends paid to noncontrolling interest holders
(5)
(5)
Short-term debt, net
385 
   
Repayments of Other Long-term Debt
(692)
   
Proceeds from Issuance of Long-term Debt
598 
   
Capital Issuance Costs
(4)
   
Other
1 
   
Net cash provided by (used in) financing activities – continuing operations
(8)
(296)
Net cash used in financing activities – discontinued operations
   
   
Net cash used in financing activities
(8)
(296)
Net change in cash and cash equivalents
(17)
(15)
Cash and cash equivalents at beginning of period
30 
209 
Cash and cash equivalents at end of period
13 
194 
Less cash and cash equivalents at end of period, discontinued operations
   
25 
Cash and cash equivalents at beginning of period
30 
 
Cash and cash equivalents at end of period
13 
169 
Union Electric Company
 
 
Cash Flows From Operating Activities:
 
 
Net income (loss)
398 
365 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
329 
313 
Amortization of nuclear fuel
70 
46 
FAC prudence review charge
   
26 
Amortization of debt issuance costs and premium/discounts
5 
6 
Deferred income taxes and investment tax credits, net
139 
62 
Allowance for equity funds used during construction
(24)
(22)
Other
1 
1 
Changes in assets and liabilities:
 
 
Receivables
(76)
(148)
Materials and supplies
3 
27 
Accounts and wages payable
(151)
(124)
Taxes accrued
(22)
260 
Assets, other
(10)
59 
Liabilities, other
6 
(78)
Pension and other postretirement benefits
(8)
(12)
Net cash provided by operating activities
660 
781 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(548)
(480)
Nuclear fuel expenditures
(28)
(34)
Money pool advances, net
   
24 
Purchases of securities - nuclear decommissioning trust fund
(365)
(147)
Sales and maturities of securities - nuclear decommissioning trust fund
354 
134 
Other
(6)
(3)
Net cash used in investing activities
(593)
(506)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(268)
(320)
Dividends on preferred stock
(3)
(3)
Money pool borrowings, net
(105)
   
Redemptions of Long-term Debt
(104)
   
Short-term debt, net
65 
   
Proceeds from Issuance of Long-term Debt
350 
   
Capital Issuance Costs
(2)
   
Net cash used in financing activities
(67)
(323)
Net change in cash and cash equivalents
   
(48)
Cash and cash equivalents at beginning of period
1 
148 
Cash and cash equivalents at end of period
1 
100 
Ameren Illinois Company
 
 
Cash Flows From Operating Activities:
 
 
Net income (loss)
158 
141 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
190 
178 
Amortization of debt issuance costs and premium/discounts
10 
11 
Deferred income taxes and investment tax credits, net
136 
120 
Other
(6)
(7)
Changes in assets and liabilities:
 
 
Receivables
80 
66 
Materials and supplies
(37)
(20)
Accounts and wages payable
1 
31 
Taxes accrued
(5)
(2)
Assets, other
(102)
(33)
Liabilities, other
(31)
1 
Pension and other postretirement benefits
(12)
(13)
Counterparty collateral, net
14 
34 
Net cash provided by operating activities
396 
507 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(633)
(462)
Other
6 
6 
Net cash used in investing activities
(627)
(456)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
   
(45)
Dividends on preferred stock
(2)
(2)
Money pool borrowings, net
(40)
(3)
Redemptions of Long-term Debt
(163)
   
Short-term debt, net
189 
   
Proceeds from Issuance of Long-term Debt
248 
   
Capital Issuance Costs
(2)
   
Other
1 
   
Net cash used in financing activities
231 
(50)
Net change in cash and cash equivalents
   
1 
Cash and cash equivalents at beginning of period
1 
   
Cash and cash equivalents at end of period
$ 1 
$ 1 
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. Dividends on Ameren’s common stock and the payment of parent company 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, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers.
•
Ameren Illinois Company, doing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 807,000 customers.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services. Ameren also has a subsidiary, ATXI, that operates a FERC rate-regulated electric transmission business and is constructing the Illinois Rivers project.
The operating results, assets, and liabilities for New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been presented separately as discontinued operations for all periods presented in this report. Unless otherwise stated, these notes to Ameren’s financial statements exclude discontinued operations for all periods presented. On January 31, 2014, Medina Valley completed its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital. See Note 12 - Divestiture Transactions and Discontinued Operations in this report for additional information regarding the discontinued operations presentation and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information regarding Ameren’s divestiture of New AER in December 2013.
The financial statements of Ameren are prepared on a consolidated basis, and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. 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

Basic earnings per share is computed by dividing net income attributable to Ameren Corporation common stockholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common stockholders by the diluted weighted-average number of common shares outstanding during the period. Diluted earnings per share reflects the potential dilution that would occur if certain stock-based performance share units were settled.

The following table presents Ameren’s basic and diluted earnings per share calculations and reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
2014
 
2013
 
2014
 
2013
Net income (loss) attributable to Ameren Corporation:
 
 
 
 
 
 
 
Continuing operations
$
294

 
$
305

 
$
541

 
$
464

Discontinued operations
(1
)
 
(3
)
 
(3
)
 
(212
)
Net income attributable to Ameren Corporation
$
293

 
$
302

 
$
538

 
$
252

 
 
 
 
 
 
 
 
Average common shares outstanding - basic
242.6

 
242.6

 
242.6

 
242.6

Assumed settlement of performance share units
1.7

 
2.5

 
1.7

 
1.8

Average common shares outstanding - diluted
244.3

 
245.1

 
244.3

 
244.4

 
 
 
 
 
 
 
 
Earnings (loss) per common share – basic:
 
 
 
 
 
 
 
Continuing operations
$
1.21

 
$
1.26

 
$
2.23

 
$
1.92

Discontinued operations
—

 
(0.01
)
 
(0.01
)
 
(0.88
)
Earnings per common share – basic
$
1.21

 
$
1.25

 
$
2.22

 
$
1.04

 
 
 
 
 
 
 
 
Earnings (loss) per common share – diluted:
 
 
 
 
 
 
 
Continuing operations
$
1.20

 
$
1.25

 
$
2.21

 
$
1.91

Discontinued operations
—

 
(0.01
)
 
(0.01
)
 
(0.88
)
Earnings per common share – diluted
$
1.20

 
$
1.24

 
$
2.20

 
$
1.03


There were no potentially dilutive securities excluded from the diluted earnings per share calculations for the three and nine months ended September 30, 2014, and 2013.
Stock-based Compensation
Ameren’s long-term incentive plan available for eligible employees and directors, the 2006 Incentive Plan, was replaced prospectively for new grants by the 2014 Incentive Plan effective April 24, 2014. The 2014 Incentive Plan provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors, and retains many of the features of the 2006 Incentive Plan. To the extent that the issuance of a share that is subject to an outstanding award under the 2006 Incentive Plan, as of April 24, 2014, would cause Ameren to exceed the maximum authorized shares under the 2006 Incentive Plan, the issuance of that share will take place under the 2014 Incentive Plan and will therefore reduce the maximum number of shares that may be granted under the 2014 Incentive Plan. The 2014 Incentive Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.
A summary of nonvested performance share units at September 30, 2014, and changes during the nine months ended September 30, 2014, under the 2006 Incentive Plan and the 2014 Incentive Plan are presented below:
 
Performance Share Units
 
Share Units
Weighted-average Fair Value Per Share Unit at Grant Date
Nonvested at January 1, 2014
1,218,544

$
33.23

Granted(a)
685,026

38.90

April Grants(b)
38,559

50.34

Forfeitures
(65,847
)
33.82

Vested(c)
(123,295
)
38.64

Nonvested at September 30, 2014
1,752,987

$
35.42

(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 under the 2006 Incentive Plan and the 2014 Incentive Plan.
(b)
In April 2014, certain executive officers were granted additional share units under the 2006 Incentive Plan and the 2014 Incentive Plan. The significant assumptions used to calculate fair value included a prorated three-year risk-free rate ranging from 0.76% to 0.79%, volatility of 12% to 18% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.
(c)
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 2014, excluding the April Grants, under the 2006 Incentive Plan and the 2014 Incentive Plan was determined to be $38.90. That amount was based on Ameren’s closing common share price of $36.16 at December 31, 2013, 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, 2014. 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 0.78%, volatility of 12% to 18% 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 renewable energy credits and emission allowances as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. Ameren Missouri’s emission allowances are allocated by the EPA and therefore are recorded at zero cost. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At September 30, 2014, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book values of both Ameren’s and Ameren Missouri’s renewable energy credits were $20 million and $22 million at September 30, 2014 and December 31, 2013, respectively.
Ameren Missouri’s and Ameren Illinois’ renewable energy credits and Ameren Missouri’s emission allowances are charged to “Purchased power” expense and “Fuel” expense, respectively, as they are used in operations. 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 nine months ended September 30, 2014, and 2013:
 
 
Three Months
 
Nine Months
 
2014
 
2013
 
2014
 
2013
Ameren Missouri
$
1

 
$
—

 
$
7

 
$
(a)

Ameren Illinois
 
1

 
 
2

 
 
7

 
 
9

Ameren
$
2

 
$
2

 
$
14

 
$
9

(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 customer and are therefore not included in revenues and expenses. They are 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 nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
2014
 
2013
 
2014
 
2013
Ameren Missouri
$
47

 
$
49

 
$
120

 
$
120

Ameren Illinois
9

 
10

 
46

 
43

Ameren
$
56

 
$
59

 
$
166

 
$
163


Uncertain Tax Positions
With the adoption of new accounting guidance in the first quarter of 2014, unrecognized tax benefits are recorded as a reduction to the deferred tax assets for net operating losses and tax credit carryforwards within “Accumulated deferred income taxes, net” on our balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities” on our balance sheets. At September 30, 2014, unrecognized tax benefits of $89 million, $13 million, and $2 million were recorded in “Accumulated deferred income taxes, net” on Ameren's, Ameren Missouri's and Ameren Illinois' balance sheets, respectively. At December 31, 2013, unrecognized tax benefits of $84 million, $15 million, and $- million previously recorded in “Other deferred credits and liabilities” on Ameren’s, Ameren Missouri’s and Ameren Illinois’ respective balance sheets were reclassified to “Accumulated deferred income taxes, net” for comparative purposes. For additional information see the Accounting and Reporting Developments section below.
The following table presents the total amount of reserves for unrecognized tax benefits (detriments) related to uncertain tax positions as of September 30, 2014, and December 31, 2013:
 
September 30, 2014
 
December 31,
2013
Ameren
$
97

 
$
90

Ameren Missouri
35

 
31

Ameren Illinois
1

 
(1
)

The following table presents the amount of reserves for unrecognized tax benefits, included in the table above, related to uncertain tax positions that would impact results of operations, if recognized, as of September 30, 2014, and December 31, 2013:
 
September 30, 2014
 
December 31,
2013
Ameren
$
55

 
$
54

Ameren Missouri
3

 
3

Ameren Illinois
—

 
—


In October 2014, a settlement was reached with the Appeals Office of the IRS for the years 2007 through 2010. During the fourth quarter of 2014, this settlement, which is primarily related to uncertain tax positions associated with the timing of research tax deductions, will result in a decrease in Ameren’s uncertain tax benefits of $16 million, of which $9 million is related to Ameren Missouri. This settlement will not have a material impact on Ameren’s or Ameren Missouri’s results of operations or liquidity.
Ameren’s federal income tax returns for the years 2011 and 2012 are before the Appeals Office of the IRS. It is reasonably possible that a settlement will be reached with the Appeals Office of the IRS in the next 12 months for the years 2011 and 2012. The potential settlement, which would primarily relate to uncertain tax positions associated with the timing of research tax deductions, is expected to result in a decrease in Ameren’s uncertain tax benefits of $6 million, all of which relates to Ameren Missouri and none of which will have a material impact on their respective results of operations or liquidity.
Ameren’s federal income tax return for the year 2013 is currently under examination by the IRS and it is reasonably possible that a settlement will be reached with the IRS examination team in the next 12 months for that year. The potential settlement, which would relate to the timing of research tax deductions and the tax basis of certain leases related to the divestiture of the merchant generation business, is expected to result in a decrease in Ameren’s uncertain tax benefits of $73 million, of which $17 million relates to Ameren Missouri and $1 million relates to Ameren Illinois. Although we are unable to estimate the impact of any potential settlement at this time, up to $55 million of the Ameren total could increase net income from Ameren’s discontinued operations. Settlement of the remaining $18 million of uncertain tax positions at Ameren, as well as those positions at Ameren Missouri and Ameren Illinois, are associated with the timing of deductions and will not have a material impact on our results of operations.
In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of our unrecognized tax benefits to fluctuate. However, other than as described above, we do not believe any such fluctuations would be material to our 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. We 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.
Asset Retirement Obligations
AROs at Ameren, Ameren Missouri and Ameren Illinois increased at September 30, 2014, compared to December 31, 2013, to reflect the accretion of obligations to their fair value and an additional ARO at Ameren and Ameren Missouri of $2 million related to the retirement costs for a CCR storage facility, partially offset by immaterial settlements.
Noncontrolling Interests
As of September 30, 2014, Ameren's noncontrolling interests were composed of the preferred stock not subject to mandatory redemption of Ameren Missouri and Ameren Illinois. All noncontrolling interests are 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 nine months ended September 30, 2014, and 2013, are shown below:
  
Three Months
 
Nine Months
 
  
2014
 
2013
 
2014
 
2013
 
Noncontrolling interests, beginning of period
$
142

 
$
151

(a) 
$
142

 
$
151

(a) 
Net income from continuing operations attributable to noncontrolling interests
2

 
2

 
5

 
5

 
Dividends paid to noncontrolling interest holders
(2
)
 
(2
)
 
(5
)
 
(5
)
 
Noncontrolling interests, end of period
$
142

 
$
151

(a) 
$
142

 
$
151

(a) 
(a)
Included the 20% EEI ownership interest not owned by Ameren prior to the divestiture of New AER to IPH. Prior to the divestiture of New AER, the assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Assets of discontinued operations” and “Liabilities of discontinued operations,” respectively. The divestiture of New AER, which included EEI, was completed in the fourth quarter of 2013. See Note 12 - Divestiture Transactions and Discontinued Operations for additional information.
Accounting and Reporting Developments
The following is a summary of recently adopted or issued authoritative accounting guidance relevant to the Ameren Companies.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. 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. This guidance was effective for the Ameren Companies beginning in the first quarter of 2014. Previously, unrecognized tax benefits were recorded in “Other deferred credits and liabilities” on Ameren's, Ameren Missouri's and Ameren Illinois' respective balance sheets. Beginning in the first quarter 2014, unrecognized tax benefits are recorded as a reduction to the deferred tax assets for net operating losses and tax credit carryforwards within “Accumulated deferred income taxes, net” on our balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities,” on the respective balance sheets. For comparative purposes, the Ameren Companies reclassified the December 31, 2013 balances in accordance with the new guidance as discussed in the Uncertain Tax Positions section above. The implementation of the additional authoritative accounting guidance did not affect the Ameren Companies' results of operations or liquidity, as this guidance is presentation-related only.
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
In April 2014, FASB issued authoritative accounting guidance that changes the criteria for reporting and qualifying for discontinued operations. Under the new guidance, a component of an entity, or a group of components of an entity, that either meets the criteria to be classified as held for sale or is disposed of by sale or otherwise, is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. The guidance includes expanded disclosure requirements for discontinued operations and additional disclosures about a disposal of an individually significant component of an entity that does not qualify for discontinued operations presentation. The guidance will be effective for the Ameren Companies in the first quarter of 2015 for components that are classified as held for sale or disposed of on or after January 1, 2015. Early adoption is permitted, but only for disposals or classifications as held for sale that have not been reported in financial statements previously issued. Therefore, Ameren’s existing discontinued operations would not be subject to the new disclosure requirements. The guidance will not affect the Ameren Companies’ results of operations, financial position, or liquidity, as this guidance is presentation-related only.
Revenue from Contracts with Customers
In May 2014, FASB issued authoritative accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The guidance requires an entity to recognize an amount of revenue for the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The guidance will be effective for the Ameren Companies in the first quarter of 2017. The Ameren Companies are currently assessing the impacts of this guidance.
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
Rate Shift Complaint and Earnings Complaint Cases
In February 2014, Noranda and 37 residential customers filed a rate shift complaint case and an earnings complaint case with the MoPSC.
On August 20, 2014, the MoPSC issued an order that rejected Noranda’s and the residential customers’ request in the rate shift complaint case. On September 12, 2014, Noranda, the MoOPC, the MIEC, and other parties filed a rehearing request, which was subsequently denied by the MoPSC.
In the earnings complaint case, Noranda and the residential customers asserted that Ameren Missouri’s electric service business is earning more than the 9.8% return on common equity authorized in the MoPSC's December 2012 electric rate order. The MoOPC, the MIEC, and other parties, participated in the earnings complaint case. On October 1, 2014, the MoPSC issued an order that rejected Noranda’s and the residential customers’ request in the earnings complaint case. On October 30, 2014, Noranda, the MoOPC, the MIEC, and other parties filed a rehearing request, which was subsequently denied by the MoPSC.
2014 Electric Rate Case
In July 2014, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $264 million. The rate request seeks recovery of increased net energy costs and rebates provided for customer-installed solar generation, as well as recovery of, and a return on, additional electric infrastructure investments made for the benefit of Ameren Missouri’s customers. Plant additions to rate base since the last electric rate order are expected to total approximately $1.4 billion through the true-up date in this rate case and include electric infrastructure investments for upgrades to the electrostatic precipitators at the coal-fired Labadie energy center, the replacement of the nuclear reactor vessel head at the Callaway energy center, two new substations in St. Louis, and the O’Fallon solar energy center, among other additions. Approximately $127 million of the request relates to an increase in net energy costs above the current levels included in base rates previously authorized by the MoPSC in its December 2012 electric rate order, 95% of which, absent initiation of this general rate proceeding, would have been reflected in rate adjustments implemented under Ameren Missouri’s existing FAC. The electric rate increase request is based on a 10.4% return on common equity, a capital structure composed of 51.6% common equity, an electric rate base for Ameren Missouri of $7.3 billion, and a test year ended March 31, 2014, with certain pro-forma adjustments expected through the true-up date of December 31, 2014.
As a part of its filing, Ameren Missouri also requested continued use of the FAC and the regulatory tracking mechanisms for storm costs, vegetation management/ infrastructure inspection costs, pension and postretirement benefits, and uncertain income tax positions that the MoPSC previously authorized in earlier electric rate orders.
The MoPSC proceeding relating to the proposed electric service rate increase will take place over a period of up to 11 months and a decision by the MoPSC in such proceeding is expected by May 2015, with rates effective by June 2015. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.
In October 2014, as part of this rate case proceeding, the MoOPC, the MIEC, and other parties, filed a rate shift request that seeks to reduce Noranda’s electric rates with an offsetting increase in electric rates for Ameren Missouri’s other customers. Ameren Missouri supplies electricity to Noranda’s aluminum smelter in southeast Missouri under a 15-year agreement, that is subject to termination as early as 2020 upon at least five years notice given by either party. Termination of the agreement by Ameren Missouri would require MoPSC approval.
Accounting Authority Order
In July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer fixed costs totaling $36 million that were not previously recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. In November 2013, the MoPSC issued an accounting authority order that allowed Ameren Missouri to seek recovery of these fixed costs in an electric rate case. Ameren Missouri’s July 2014 electric rate case filing requested recovery of these fixed costs over five years. In February 2014, the MIEC and the MoOPC filed appeals of the MoPSC’s November 2013 accounting authority order with the Missouri Court of Appeals, Western District. Ameren Missouri has not recorded any potential revenue associated with this accounting authority order.
Illinois
IEIMA
Under the provisions of the IEIMA, Ameren Illinois’ electric delivery service rates are subject to an annual revenue requirement reconciliation to its actual costs. Throughout each 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 customer billings for that year and its 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 September 30, 2014, Ameren Illinois had recorded regulatory assets of $76 million and $64 million, respectively, to reflect its expected 2014 and 2013 revenue requirement reconciliation adjustments, with interest. As of September 30, 2014, Ameren Illinois had recorded a regulatory liability of $13 million to reflect its 2012 revenue requirement reconciliation adjustment, with interest, which is being refunded to customers during 2014.
In December 2013, the ICC issued an order in Ameren Illinois' annual formula rate update filing, which was based on 2012 recoverable costs and expected net plant additions for 2013. The ICC order established rates for 2014. In February 2014, Ameren Illinois filed an appeal to the Appellate Court of the Fourth District of Illinois regarding the rate treatment of accumulated deferred income taxes related to the transfer of former Ameren Missouri electric assets located in Illinois to Ameren Illinois.
In April 2014, Ameren Illinois filed with the ICC its annual electric delivery service formula rate update to establish the revenue requirement used to set rates for 2015. Pending ICC approval, Ameren Illinois’ update filing, as revised in July 2014, will result in a $205 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2015. This update reflects an increase to the annual formula rate based on 2013 actual costs and expected net plant additions for 2014, an increase to include the annual reconciliation of the revenue requirement in effect for 2013 to the actual costs incurred in that year, and an increase resulting from the conclusion of a refund to customers in 2014 for the 2012 revenue requirement reconciliation. In August 2014, the ICC staff submitted its revised calculation of the revenue requirement. The ICC staff recommended a $205 million increase in Ameren Illinois’ electric delivery service revenue requirement. Other intervenors requested an electric delivery service revenue requirement up to $7 million lower than the revenue requirement recommended by the ICC staff. In October 2014, the administrative law judges issued a proposed order that reflected an increase to Ameren Illinois’ electric delivery service revenue requirement of $204 million. A final ICC decision on this April 2014 filing is expected by December 2014.
2013 Natural Gas Delivery Service Rate Case
In December 2013, the ICC issued a rate order that approved an increase in revenues for natural gas delivery service of $32 million. The revenue increase was based on a 9.1% return on common equity, a capital structure composed of 51.7% common equity, and a rate base of $1.1 billion. The rate order was based on a 2014 future test year. The rate changes became effective January 1, 2014. In March 2014, Ameren Illinois filed an appeal of the allowed return on common equity included in the ICC's order and also appealed the rate treatment of accumulated deferred income taxes related to the transfer of former Ameren Missouri natural gas assets located in Illinois to Ameren Illinois with the Appellate Court of the Fourth District of Illinois. Ameren Illinois sought a 10.4% return on common equity in this rate case.
ATXI Transmission Project
The Spoon River project in northwest Illinois is a MISO-approved transmission line project. In August 2014, ATXI made a filing with the ICC requesting a certificate of public convenience and necessity and project approval for the Spoon River project. A decision is expected from the ICC in 2015. A certificate of public convenience and necessity is required before ATXI can proceed with right-of-way acquisition.
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 with no material impact on net income. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. In November 2012, a FERC administrative law judge issued an initial decision finding that refunds were due to the wholesale customers. In September 2014, FERC issued an order affirming certain findings in the initial decision. Ameren and Ameren Illinois recognized in “Current regulatory liabilities” an estimate of $24 million and $13 million as of September 30, 2014, and December 31, 2013, respectively, for the refund due to the wholesale customers relating to billings since March 2011. In October 2014, Ameren Illinois refunded $24 million, including interest, to the wholesale customers and requested a rehearing on certain aspects of the order.
Ameren Illinois Electric Transmission Rate Refund
In July 2012, FERC issued an order concluding that Ameren Illinois improperly included acquisition premiums, including goodwill, in determining the common equity used in its electric transmission formula rate, and thereby inappropriately recovered a higher amount from its electric transmission customers. The order required Ameren Illinois to make refunds to customers for such improperly included amounts. In August 2012, Ameren Illinois filed a request for a rehearing of this order.
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 Illinois’ conclusion that no refund was warranted. In June 2013, FERC issued an order that rejected Ameren Illinois' November 2012 refund report and provided guidance as to the filing of a new refund report. In July 2013, Ameren Illinois filed a revised refund report based on the guidance provided in the June 2013 order, as well as a request for a rehearing of that order. Ameren Illinois' July 2013 refund report also concluded that no refund was warranted.
In June 2014, FERC issued an order that denied Ameren Illinois’ rehearing requests of the July 2012 order and the June 2013 order. Separately, in June 2014, FERC issued an order that established hearing and settlement procedures for Ameren Illinois’ July 2013 refund report. In July 2014, Ameren Illinois filed an appeal of FERC’s orders denying rehearing of the July 2012 and June 2013 orders with the United States Court of Appeals for the District of Columbia Circuit. Also in July 2014, Ameren Illinois separately filed a request for rehearing with FERC of its June 2014 order regarding the July 2013 refund report.
Ameren Illinois estimates the maximum pretax charge to earnings for this possible refund obligation through December 31, 2014, would be $19 million, before interest charges. For the nine months ended September 30, 2014, Ameren and Ameren Illinois recorded a $4 million reduction to “Operating Revenues - Electric” with a corresponding increase to “Current regulatory liabilities” for its estimate of the refund due to electric transmission customers based on the June 2014 order. If Ameren Illinois were to determine that a refund to its electric transmission customers in excess of the amount already recorded is probable, an additional charge to earnings would be recorded in the period in which that determination is made.
FERC Complaint Case
In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed base return on common equity for FERC-regulated MISO transmission rate base to 9.15%, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed base return on common equity for MISO transmission owners is 12.38%. In October 2014, FERC issued an order establishing settlement procedures and, if necessary, hearing procedures regarding the allowed base return on common equity and denied all other aspects of the MISO complaint case. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed base return on common equity, which would result in a refund for transmission service revenues earned from the refund effective date of November 12, 2013.
In October 2014, FERC issued an order, which confirmed its June 2014 order, reducing the allowed base return on common equity for New England transmission owners from 11.14% to 10.57%, with rate incentives allowed up to 11.74%. The FERC orders in the New England transmission owners’ case applied observable market data from October 2012 to March 2013 to determine the allowed base return on common equity. FERC expects the evidence and the calculation used in the New England transmission owners’ case to guide its decision in the MISO complaint case. The calculation FERC will use to establish the allowed base return on common equity, which is based on a unique time period for each complaint case, will require multiple inputs based on observable market data specific to the utility industry and broader macroeconomic data. The unique time period of observable market data for the MISO complaint case has not been established by FERC. Due to the wide range of potential outcomes and significant uncertainty regarding the value of inputs required in FERC’s calculation, the Ameren Companies cannot reasonably estimate the impact, if any, that a resolution in the MISO complaint case could have on their allowed base return on common equity.
On November 6, 2014, we filed a request with FERC to include an incentive adder of up to 50 basis points for participation in an RTO on the allowed base return on common equity. The filing requests a November 7, 2014 effective date and seeks authorization to defer collection of the incentive adder until after the issuance of the final order addressing the pending MISO complaint case discussed above. FERC is required to issue an order within 60 days of our filing.
If MISO’s allowed base return on common equity was lowered to 10.57%, as established in the New England transmission owners’ case, with no additional rate incentives, the required refund for Ameren and Ameren Illinois would be $14 million and $11 million, respectively, from the refund effective date of November 12, 2013 through September 30, 2014. The estimated annual reduction in revenues if the MISO return on common equity was 10.57% for Ameren and Ameren Illinois would be $16 million and $12 million, respectively. Ameren Missouri would not expect that a reduction in the FERC-allowed base return on common equity for MISO transmission owners would be material to its results of operations, financial position or liquidity. If Ameren and Ameren Illinois were to determine that a refund to their electric transmission customers could be reasonably estimated, a charge to earnings would be recorded for the refund in the period in which that determination is made.
Ameren Missouri Power Purchase Agreement with Entergy
Beginning in 2005, FERC issued a series of orders addressing a complaint filed in 2001 by the Louisiana Public Service Commission against Entergy and certain of its affiliates. The complaint alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing Ameren Missouri in 2007 for additional charges under a 165-megawatt power purchase agreement, which expired August 31, 2009. In May 2012, FERC issued an order stating that Entergy should not have included additional charges to Ameren Missouri under the power purchase agreement. Pursuant to the order, in June 2012, Entergy paid Ameren Missouri $31 million. In July 2012, Entergy filed an appeal of FERC's May 2012 order to the United States Court of Appeals for the District of Columbia Circuit, which was subsequently dismissed on a procedural issue. In November 2013, Entergy refiled the appeal of FERC's May 2012 order with the United States Court of Appeals for the District of Columbia Circuit. Ameren is not able to predict when or how the court will rule on Entergy's appeal.
The Louisiana Public Service Commission appealed FERC’s orders regarding Louisiana Public Service Commission’s complaint against Entergy Services, Inc. to the United States Court of Appeals for the District of Columbia Circuit. In April 2008, that court ordered further FERC proceedings regarding Louisiana Public Service Commission’s complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. Ameren Missouri is unable to predict when or how FERC will respond to the court’s decisions. Ameren Missouri estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. Ameren Missouri believes that the likelihood of incurring an expense is not probable, and therefore no liability has been recorded as of September 30, 2014.
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.
Ameren Missouri estimated the total cost required to obtain a small modular reactor COL to be $80 million to $120 million. As of September 30, 2014, Ameren Missouri had capitalized investments of $69 million for the development of a new nuclear energy center. Ameren Missouri is currently evaluating all potential nuclear technologies in order to maintain an option for nuclear power in the future.
All of Ameren Missouri's capitalized investments for the development of a new nuclear energy center will remain capitalized while management pursues options to maximize the value of its investment. If efforts to license additional nuclear generation are abandoned or management concludes it is probable that 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, drawings under committed credit agreements, commercial paper issuances, or, in the case of Ameren Missouri and Ameren Illinois, short-term intercompany borrowings.
The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement, both of which expire on November 14, 2017, were not utilized for direct borrowings during the nine months ended September 30, 2014, but they were used to support commercial paper issuances and to issue letters of credit. 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 September 30, 2014, was $1.3 billion.
Commercial Paper
The following table presents commercial paper outstanding at Ameren (parent), Ameren Missouri and Ameren Illinois as of September 30, 2014, and December 31, 2013. Ameren Illinois established a commercial paper program in May 2014.
  
September 30, 2014
 
December 31, 2013
Ameren (parent)
$
499

 
$
368

Ameren Missouri
65

 
—

Ameren Illinois
189

 
—

Ameren Consolidated
$
753

 
$
368

The following table summarizes the commercial paper activity and relevant interest rates under Ameren’s (parent), Ameren Missouri’s and Ameren Illinois’ commercial paper programs for the nine months ended September 30, 2014, and 2013:
 
 
Ameren (parent)
Ameren Missouri
Ameren Illinois
Ameren Consolidated
2014
 
 
 
 
 
 
Average daily commercial paper outstanding
 
$
386

 
$
141

$
157

$
609

Weighted-average interest rate
 
0.36
%
 
0.38
%
0.31
%
0.35
%
Peak commercial paper during period(a)
 
$
531

 
$
495

$
300

$
907

Peak interest rate
 
0.75
%
 
0.70
%
0.34
%
0.75
%
2013
 
 
 
 
 
 
Average daily commercial paper outstanding
 
$
26

 
$
—

$
—

$
26

Weighted-average interest rate
 
0.52
%
 
—
%
—
%
0.52
%
Peak commercial paper during period(a)
 
$
92

 
$
—

$
—

$
92

Peak interest rate
 
0.85
%
 
—
%
—
%
0.85
%

(a)
The timing of peak commercial paper issuances varies by company, and therefore the peak amounts presented by company might not equal the Ameren Consolidated peak commercial paper issuances for the period.
Indebtedness Provisions and Other Covenants
The information below is 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 September 30, 2014, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 49%, 48% and 46%, 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 at least 2.0 to 1.0, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2012 Illinois Credit Agreement. Ameren’s ratio as of September 30, 2014, was 6.1 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. The calculation of Ameren’s ratios discussed above includes both continuing and discontinued operations.
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. The Ameren Companies were in compliance with the provisions and covenants of their credit agreements at September 30, 2014.
Money Pools
Ameren (parent) has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Ameren Services is responsible for the operation and administration of the money pool agreements.
Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren (parent) may participate in the utility money pool only as a lender. Surplus internal funds are 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. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2014, was 0.10% and 0.23%, respectively (2013 - 0.05% and 0.08%, respectively).
See Note 8 - 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 nine months ended September 30, 2014, and 2013.
Long-Term Debt And Equity Financings
LONG-TERM DEBT AND EQUITY FINANCINGS
LONG-TERM DEBT
Ameren (parent)
In May 2014, Ameren (parent) repaid at maturity $425 million of its 8.875% senior unsecured notes due May 15, 2014, plus accrued interest. The notes were repaid with proceeds from commercial paper issuances.
Ameren Missouri
In April 2014, Ameren Missouri issued $350 million of 3.50% senior secured notes due April 15, 2024, with interest payable semiannually on April 15 and October 15 of each year, beginning October 15, 2014. Ameren Missouri received proceeds of $348 million, which were used to repay at maturity $104 million of its 5.50% senior secured notes due May 15, 2014 and to repay a portion of its short-term debt.
Ameren Illinois
In January 2014, Ameren Illinois redeemed the following environmental improvement and pollution control revenue bonds at par value plus accrued interest:
Environmental improvement and pollution control revenue bonds
Principal Amount
5.90% Series 1993 due 2023(a)
$
32

5.70% 1994A Series due 2024(a)
36

5.95% 1993 Series C-1 due 2026
35

5.70% 1993 Series C-2 due 2026
8

5.40% 1998A Series due 2028
19

5.40% 1998B Series due 2028
33

Total amount redeemed
$
163

(a)
Less than $1 million principal amount of the bonds remain outstanding after redemption.
In June 2014, Ameren Illinois issued $250 million of 4.30% senior secured notes due July 1, 2044, with interest payable semiannually on January 1 and July 1 of each year, beginning January 1, 2015. Ameren Illinois received proceeds of $246 million, which were used to repay a portion of its short-term debt.
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 September 30, 2014, at an assumed annual interest rate of 5% and dividend rate of 6%.
 
 
Required Interest
Coverage Ratio(a)
 
Actual Interest
Coverage Ratio
 
Bonds Issuable(b)
 
Required Dividend
Coverage Ratio(c)
 
Actual Dividend
Coverage Ratio
 
Preferred Stock
Issuable
 
Ameren Missouri
 
≥2.0
 
4.6
$
3,304

 
≥2.5
 
126.3
$
2,823

 
Ameren Illinois
 
≥2.0
 
6.7
 
3,636

(d) 
≥1.5
 
2.4
 
203

(e) 
(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 $833 million and $204 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.
(e)
Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation.
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.” 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% equity capital structure. As of September 30, 2014, Ameren Illinois had a 54% equity capital structure.
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 September 30, 2014, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future. See Note 12 - Divestiture Transactions and Discontinued Operations for Ameren (parent) guarantees and letters of credit issued to support New AER based on the transaction agreement with IPH.
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 for the three and nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
 
2014
 
2013
 
2014
 
2013
 
Ameren:(a)
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
10

 
$
10

 
$
26

  
$
26

 
Interest income on industrial development revenue bonds
6

 
7

 
20

  
21

 
Interest income
3

 
2

 
8

 
3

 
Other
2

 
1

 
6

 
1

 
Total miscellaneous income
$
21

 
$
20

 
$
60

  
$
51

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
3

 
$
2

 
$
9

 
$
7

 
Other
4

 
3

 
11

  
11

 
Total miscellaneous expense
$
7

 
$
5

 
$
20

  
$
18

 
Ameren Missouri:
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
9

 
$
8

 
$
24

  
$
22

 
Interest income on industrial development revenue bonds
6

 
7

 
20

 
21

 
Interest income
—

 
1

 
1

 
1

 
Total miscellaneous income
$
15

 
$
16

 
$
45

  
$
44

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
2

 
$
—

 
$
5

  
$
3

 
Other
2

 
2

 
5

  
7

 
Total miscellaneous expense
$
4

 
$
2

 
$
10

  
$
10

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

 
$
2

 
$
2

  
$
4

 
Interest income
2

 
1

 
5

  
2

 
Other
1

 
1

 
5

 
1

 
Total miscellaneous income
$
4

 
$
4

 
$
12

  
$
7

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
—

 
$
—

 
$
3

 
$
3

 
Other
2

 
3

 
4

  
4

 
Total miscellaneous expense
$
2

 
$
3

 
$
7

  
$
7

 
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Derivative Financial Instruments
DERIVATIVE FINANCIAL INSTRUMENTS
DERIVATIVE FINANCIAL INSTRUMENTS
We use derivatives to manage the risk of changes in market prices for natural gas, 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 natural gas and uranium inventories that differ from the cost of those commodities in inventory; and
•
actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.
The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of September 30, 2014, and December 31, 2013. As of September 30, 2014, these contracts ran through October 2017, October 2019, May 2032, and October 2016 for fuel oils, natural gas, power, and uranium, respectively.
  
Quantity (in millions, except as indicated)
 
2014
2013
Commodity
Ameren Missouri
Ameren Illinois
Ameren
Ameren Missouri
Ameren Illinois
Ameren
Fuel oils (in gallons)(a)
52

(b)

52

66

(b)

66

Natural gas (in mmbtu)
23

102

125

28

108

136

Power (in megawatthours)
1

11

12

3

11

14

Uranium (pounds in thousands)
557

(b)

557

796

(b)

796

(a)
Fuel oils consist of ultra-low-sulfur diesel, on-highway diesel, and crude oil.
(b)
Not applicable.
Authoritative accounting guidance regarding derivative instruments requires that all contracts considered to be derivative instruments be recorded on the balance sheet at their fair values, unless the NPNS exception applies. See Note 7 - Fair Value Measurements for a discussion of our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.
If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. 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. We believe derivative losses and gains 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. As of September 30, 2014, and December 31, 2013, all contracts that qualify for hedge accounting received regulatory deferral.
Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible commodity contracts.
The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of September 30, 2014, and December 31, 2013:
 
Balance Sheet Location
 
Ameren  Missouri
 
Ameren  Illinois
 
Ameren
2014
 
 
 
 
 
 
Fuel oils
Other current assets
 
$
3

 
$
—

 
$
3

Natural gas
Other current assets
 
—

 
1

 
1

 
Other assets
 
—

 
1

 
1

Power
Other current assets
 
10

 
—

 
10

 
Other assets
 
1

 
—

 
1

 
Total assets
 
$
14

 
$
2

 
$
16

Fuel oils
Other current liabilities
 
$
5

 
$
—

 
$
5

 
Other deferred credits and liabilities
 
1

 
—

 
1

Natural gas
Other current liabilities
 
3

 
16

 
19

 
Other deferred credits and liabilities
 
3

 
6

 
9

Power
Other current liabilities
 
6

 
8

 
14

 
Other deferred credits and liabilities
 
—

 
116

 
116

Uranium
Other current liabilities
 
2

 
—

 
2

 
Other deferred credits and liabilities
 
1

 
—

 
1

 
Total liabilities
 
$
21

 
$
146

 
$
167

2013
 
 
 
 
 
 
Fuel oils
Other current assets
 
$
6

 
$
—

 
$
6

 
Other assets
 
3

 
—

 
3

Natural gas
Other current assets
 
1

 
1

 
2

Power
Other current assets
 
23

 
—

 
23

 
Total assets
 
$
33

 
$
1

 
$
34

Fuel oils
Other current liabilities
 
$
2

 
$
—

 
$
2

 
Other deferred credits and liabilities
 
1

 
—

 
1

Natural gas
Other current liabilities
 
5

 
27

 
32

 
Other deferred credits and liabilities
 
6

 
19

 
25

Power
Other current liabilities
 
4

 
9

 
13

 
Other deferred credits and liabilities
 
—

 
99

 
99

Uranium
Other current liabilities
 
5

 
—

 
5

 
Other deferred credits and liabilities
 
1

 
—

 
1

 
Total liabilities
 
$
24

 
$
154

 
$
178



The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred as regulatory assets or regulatory liabilities as of September 30, 2014, and December 31, 2013:
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
2014
 
 
 
 
 
Fuel oils derivative contracts(a)
$
(5
)
 
$
—

 
$
(5
)
Natural gas derivative contracts(b)
(6
)
 
(20
)
 
(26
)
Power derivative contracts(c)
5

 
(124
)
 
(119
)
Uranium derivative contracts(d)
(3
)
 
—

 
(3
)
2013
 
 
 
 
 
Fuel oils derivative contracts
$
2

 
$
—

 
$
2

Natural gas derivative contracts
(10
)
 
(45
)
 
(55
)
Power derivative contracts
19

 
(108
)
 
(89
)
Uranium derivative contracts
(6
)
 
—

 
(6
)
(a)
Represents net losses associated with fuel oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2017. Current losses deferred as regulatory assets include $4 million and $4 million at Ameren and Ameren Missouri, respectively.
(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 2018 at Ameren Illinois. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively. Current losses deferred as regulatory assets include $19 million, $3 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively.
(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. Current gains deferred as regulatory liabilities include $10 million and $10 million at Ameren and Ameren Missouri. Current losses deferred as regulatory assets include $14 million, $6 million, and $8 million at Ameren, Ameren Missouri and Ameren Illinois, respectively.
(d)
Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through December 2016. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri, respectively.
Derivative instruments are subject to various credit-related losses in the event of nonperformance by counterparties to the transaction. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk. Our credit risk management program involves establishing credit limits and collateral requirements for counterparties, using master trading and netting agreements, and reporting daily exposure to senior management.
We believe that entering into master trading and netting agreements mitigates the level of financial loss that could result from default by allowing net settlement of derivative assets and liabilities. We generally enter into the following master trading and netting agreements: (1) the International Swaps and Derivatives Association Agreement, a standardized financial natural gas and electric contract; (2) the Master Power Purchase and Sale Agreement, created by the Edison Electric Institute and the National Energy Marketers Association, a standardized contract for the purchase and sale of wholesale power; and (3) the North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at the master trading and netting agreement level by counterparty.
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 September 30, 2014, and December 31, 2013:
 
 
 
 
Gross Amounts Not Offset in the Balance Sheet
 
 
Commodity Contracts Eligible to be Offset
 
Gross Amounts Recognized in the Balance Sheet
 
Derivative Instruments
 
Cash Collateral Received/Posted(a)
 
Net
Amount
2014
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
14

 
$
7

 
$
—

 
$
7

Ameren Illinois
 
2

 
1

 
—

 
1

Ameren
 
$
16

 
$
8

 
$
—

 
$
8

Liabilities:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
21

 
$
7

 
$
5

 
$
9

Ameren Illinois
 
146

 
1

 
—

 
145

Ameren
 
$
167

 
$
8

 
$
5

 
$
154

2013
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
33

 
$
9

 
$
—

 
$
24

Ameren Illinois
 
1

 
1

 
—

 
—

Ameren
 
$
34

 
$
10

 
$
—

 
$
24

Liabilities:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
24

 
$
9

 
$
9

 
$
6

Ameren Illinois
 
154

 
1

 
15

 
138

Ameren
 
$
178

 
$
10

 
$
24

 
$
144

(a)
Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.
Concentrations of Credit Risk
In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into groupings according to the primary business in which each engages. We calculate maximum exposures based on the gross fair value of financial instruments, including accrual and NPNS contracts. As of September 30, 2014, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri and Ameren Illinois' maximum exposure was $6 million, $4 million, and $2 million, respectively. As of December 31, 2013, if counterparty groups were to fail completely to perform on contracts, Ameren, Ameren Missouri and Ameren Illinois' maximum exposure was $13 million, $12 million, and $1 million, respectively. The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. As of September 30, 2014, the potential loss after consideration of the application of master trading and netting agreements and collateral held for Ameren, Ameren Missouri and Ameren Illinois was $4 million, $3 million, and $1 million, respectively. As of December 31, 2013, the potential loss after consideration of the application of master trading and netting agreements and collateral held for Ameren, Ameren Missouri and Ameren Illinois was $6 million, $6 million, and $- million, respectively.
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 September 30, 2014, and December 31, 2013, 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 September 30, 2014, or December 31, 2013, 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)
2014
 
 
 
 
 
Ameren Missouri
$
62

 
$
2

 
$
57

Ameren Illinois
61

 
—

 
56

Ameren
$
123

 
$
2

 
$
113

2013
 
 
 
 
 
Ameren Missouri
$
70

 
$
2

 
$
67

Ameren Illinois
75

 
15

 
55

Ameren
$
145

 
$
17

 
$
122

(a)
Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures.
(b)
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.
Fair Value Measurements
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:
Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri’s nuclear decommissioning trust fund.
The market approach is used to measure the fair value of equity securities held in Ameren Missouri’s nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index comprises stocks of large capitalization companies.
Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including corporate bonds and other fixed-income securities, United States Treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.
Fixed income securities are valued using prices from independent industry recognized data vendors who provide values that are either exchange-based or matrix-based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market-corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the nuclear decommissioning trust fund are primarily corporate bonds, asset-backed securities and United States agency bonds.
Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power 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 reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.
We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.
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 September 30, 2014:
 
 
Fair Value
 
 
 
Weighted Average
 
 
Assets
Liabilities
Valuation Technique(s)
Unobservable Input
Range
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
3

$
(3
)
Option model
Volatilities(%)(b)
2 - 27
14
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.25 - 1
0.72
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
0.43
(e)
 
Natural gas
1

—

Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.10) - 0
(0.10)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.30 - 2
0.62
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
Power(f)
10

(129
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
29 - 59
35
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,853) - 2,087
199
 
 
 
 
 
Nodal basis($/MWh)(c)
(6) - 0
(3)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.40
(e)
 
 
 
 
 
Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
2
(e)
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
35 - 41
36
Ameren Missouri
Fuel oils
$
3

$
(3
)
Option model
Volatilities(%)(b)
2 - 27
14
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.25 - 1
0.72
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
0.43
(e)
 
Power(f)
10

(5
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
30 - 59
48
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,853) - 2,087
199
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.40
(e)
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
0.43
(e)
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
35 - 41
36
Ameren Illinois
Natural gas
$
1

$
—

Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.10) - 0
(0.10)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.30 - 2
0.62
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
Power(f)
—

(124
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)
29 - 42
33
 
 
 
 
 
Nodal basis($/MWh)(b)
(6) - 0
(3)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
2
(e)
 
 
 
 
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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.
(e)
Not applicable.
(f)
Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 use fundamentally modeled pricing by month for peak and off-peak demand.
(g)
Escalation rate applies to power prices 2026 and beyond.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2013:
 
 
Fair Value
 
 
 
Weighted Average
 
 
Assets
Liabilities
Valuation Technique(s)
Unobservable Input
Range
Level 3 Derivative asset and liability – commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
8

$
(3
)
Option model
Volatilities(%)(b)
10 - 35
16
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 2
1
 
Power(e)
21

(110
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
25 - 51
32
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,594) - 945
305
 
 
 
 
 
Nodal basis($/MWh)(c)
(3) - (1)
(2)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.39 - 0.50
0.42
 
 
 
 
 
Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)
2
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
3 - 4
4
 
 


Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
 
Uranium
—

(6
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
34 - 41
36
Ameren Missouri
Fuel oils
$
8

$
(3
)
Option model
Volatilities(%)(b)
10 - 35
16
 
 


Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 2
1
 
Power(e)
21

(2
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
25 - 51
40
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,594) - 945
305
 
 


 
Nodal basis($/MWh)(c)
(3) - (1)
(2)
 
 


 
Counterparty credit risk(%)(c)(d)
0.39 - 0.50
0.42
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
2
(f)
 
Uranium
—

(6
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
34 - 41
36
Ameren Illinois
Power(e)
$
—

$
(108
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)
27 - 36
30
 
 
 
 
 
Nodal basis($/MWh)(b)
(4) - 0
(2)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
2
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
3 - 4
4
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(c)
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(d)
Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.
(e)
Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 use fundamentally modeled pricing by month for peak and off-peak demand.
(f)
Not applicable.
(g)
Escalation rate applies to power prices 2026 and beyond.
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. No gains or losses related to valuation adjustments for counterparty default risk were recorded at Ameren, Ameren Missouri or Ameren Illinois in the first nine months of 2014 or 2013. At September 30, 2014, the counterparty default risk liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, and $1 million, for Ameren, Ameren Missouri and Ameren Illinois, respectively. At December 31, 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.
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 September 30, 2014:
 
 
 
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
 
$
—

 
$
—

 
$
3

 
$
3

 
 
Natural gas
 
—

 
1

 
1

 
2

 
 
Power
 
—

 
1

 
10

 
11

 
 
Total derivative assets - commodity contracts
 
$
—

 
$
2

 
$
14

 
$
16

 
 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
 
Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
348

 
—

 
—

 
348

 
 
Debt securities:
 
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
60

 
—

 
60

 
 
Municipal bonds
 
—

 
2

 
—

 
2

 
 
U.S. treasury and agency securities
 
—

 
100

 
—

 
100

 
 
Asset-backed securities
 
—

 
11

 
—

 
11

 
 
Other
 
—

 
5

 
—

 
5

 
 
Total nuclear decommissioning trust fund
 
$
349

 
$
178

 
$
—

 
$
527

(b) 
 
Total Ameren
 
$
349

 
$
180

 
$
14

 
$
543

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

 
$
—

 
$
3

 
$
3

 
 
Power
 
—

 
1

 
10

 
11

 
 
Total derivative assets - commodity contracts
 
$
—

 
$
1

 
$
13

 
$
14

 
 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
 
Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
348

 
—

 
—

 
348

 
 
Debt securities:
 
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
60

 
—

 
60

 
 
Municipal bonds
 
—

 
2

 
—

 
2

 
 
U.S. treasury and agency securities
 
—

 
100

 
—

 
100

 
 
Asset-backed securities
 
—

 
11

 
—

 
11

 
 
Other
 
—

 
5

 
—

 
5

 
 
Total nuclear decommissioning trust fund
 
$
349

 
$
178

 
$
—

 
$
527

(b) 
 
Total Ameren Missouri
 
$
349

 
$
179

 
$
13

 
$
541

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

 
$
1

 
$
1

 
$
2

 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
3

 
$
—

 
$
3

 
$
6

 
 
Natural gas
 
2

 
26

 
—

 
28

 
 
Power
 
—

 
1

 
129

 
130

 
 
Uranium
 
—

 
—

 
3

 
3

 
 
Total Ameren
 
$
5

 
$
27

 
$
135

 
$
167

 
Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
3

 
$
—

 
$
3

 
$
6

 
 
Natural gas
 
2

 
4

 
—

 
6

 
 
Power
 
—

 
1

 
5

 
6

 
 
Uranium
 
—

 
—

 
3

 
3

 
 
Total Ameren Missouri
 
$
5

 
$
5

 
$
11

 
$
21

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

 
$
22

 
$
—

 
$
22

 
 
Power
 
—

 
—

 
124

 
124

 
 
Total Ameren Illinois
 
$
—

 
$
22

 
$
124

 
$
146

 
(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, 2013:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
1

 
$
—

 
$
8

 
$
9

 
Natural gas
 
—

 
2

 
—

 
2

 
Power
 
—

 
2

 
21

 
23

 
Total derivative assets - commodity contracts
 
$
1

 
$
4

 
$
29

 
$
34

 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
332

 
—

 
—

 
332

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
52

 
—

 
52

 
Municipal bonds
 
—

 
2

 
—

 
2

 
U.S. treasury and agency securities
 
—

 
94

 
—

 
94

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
335

 
$
159

 
$
—

 
$
494

 
Total Ameren
 
$
336

 
$
163

 
$
29

 
$
528

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

 
$
—

 
$
8

 
$
9

 
Natural gas
 
—

 
1

 
—

 
1

 
Power
 
—

 
2

 
21

 
23

 
Total derivative assets - commodity contracts
 
$
1

 
$
3

 
$
29

 
$
33

 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
332

 
—

 
—

 
332

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
52

 
—

 
52

 
Municipal bonds
 
—

 
2

 
—

 
2

 
U.S. treasury and agency securities
 
—

 
94

 
—

 
94

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
335

 
$
159

 
$
—

 
$
494

 
Total Ameren Missouri
 
$
336

 
$
162

 
$
29

 
$
527

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

 
$
1

 
$
—

 
$
1

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

 
$
—

 
$
3

 
$
3

 
Natural gas
 
3

 
54

 
—

 
57

 
Power
 
—

 
2

 
110

 
112

 
Uranium
 
—

 
—

 
6

 
6

 
Total Ameren
 
$
3

 
$
56

 
$
119

 
$
178

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

 
$
—

 
$
3

 
$
3

 
Natural gas
 
3

 
8

 
—

 
11

 
Power
 
—

 
2

 
2

 
4

 
Uranium
 
—

 
—

 
6

 
6

 
Total Ameren Missouri
 
$
3

 
$
10

 
$
11

 
$
24

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

 
$
46

 
$
—

 
$
46

 
Power
 
—

 
—

 
108

 
108

 
Total Ameren Illinois
 
$
—

 
$
46

 
$
108

 
$
154

(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.

The following table 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 September 30, 2014:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
2

$
(a)

$
2

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

 
(2
)
Ending balance at September 30, 2014
$
—

$
(a)

$
—

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(2
)
$
(a)

$
(2
)
Natural gas:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
—

$
—

$
—

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

 
1

 
1

Ending balance at September 30, 2014
$
—

$
1

$
1

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
—

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
15

$
(103
)
$
(88
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(5
)
 
(23
)
 
(28
)
Settlements
 
(5
)
 
2

 
(3
)
Ending balance at September 30, 2014
$
5

$
(124
)
$
(119
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(6
)
$
(22
)
$
(28
)
Uranium:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
(7
)
$
(a)

$
(7
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
3

 
(a)

 
3

Settlements
 
1

 
(a)

 
1

Ending balance at September 30, 2014
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
3

$
(a)

$
3

(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 September 30, 2013:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
3

$
(a)

$
3

Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
1

 
(a)

 
1

Purchases
 
1

 
(a)

 
1

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(1
)
 
(a)

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

$
(a)

$
3

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

$
(a)

$
1

Natural gas:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
(1
)
$
2

$
1

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

 
(2
)
 
(2
)
Purchases
 
1

 
—

 
1

Ending balance at September 30, 2013
$
—

$
—

$
—

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

$
(1
)
$
(1
)
Power:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
37

$
(80
)
$
(43
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(3
)
 
(17
)
 
(20
)
Sales
 
1

 
—

 
1

Settlements
 
(6
)
 
3

 
(3
)
Transfers into Level 3
 
(1
)
 
—

 
(1
)
Ending balance at September 30, 2013
$
28

$
(94
)
$
(66
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
(2
)
$
(16
)
$
(18
)
Uranium:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
(3
)
$
(a)

$
(3
)
Purchases
 
(2
)
 
(a)

 
(2
)
Ending balance at September 30, 2013
$
(5
)
$
(a)

$
(5
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
(2
)
$
(a)

$
(2
)
(a)
Not applicable.
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 nine months ended September 30, 2014:
  
 
Net derivative commodity contracts
Nine Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
5

$
(a)

$
5

Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(3
)
 
(a)

 
(3
)
Settlements
 
(2
)
 
(a)

 
(2
)
Ending balance at September 30, 2014
$
—

$
(a)

$
—

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(2
)
$
(a)

$
(2
)
Natural gas:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
—

$
—

$
—

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

 
1

 
1

Purchases
 
—

 
(1
)
 
(1
)
Settlements
 
—

 
1

 
1

Ending balance at September 30, 2014
$
—

$
1

$
1

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
—

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
19

$
(108
)
$
(89
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(23
)
 
(19
)
 
(42
)
Purchases
 
34

 
—

 
34

Settlements
 
(25
)
 
3

 
(22
)
Ending balance at September 30, 2014
$
5

$
(124
)
$
(119
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(3
)
$
(21
)
$
(24
)
Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
(6
)
$
(a)

$
(6
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(1
)
 
(a)

 
(1
)
Settlements
 
4

 
(a)

 
4

Ending balance at September 30, 2014
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
—

$
(a)

$
—

(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 nine months ended September 30, 2013:
  
 
Net derivative commodity contracts
Nine Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
5

$
(a)

$
5

Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(1
)
 
(a)

 
(1
)
Purchases
 
2

 
(a)

 
2

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(2
)
 
(a)

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

$
(a)

$
3

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

$
(a)

$
—

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

$
—

$
—

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

 
(1
)
 
(1
)
Purchases
 
—

 
1

 
1

Ending balance at September 30, 2013
$
—

$
—

$
—

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

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
11

$
(111
)
$
(100
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
3

 
(2
)
 
1

Purchases
 
40

 
—

 
40

Sales
 
1

 
—

 
1

Settlements
 
(28
)
 
19

 
(9
)
Transfers into Level 3
 
(3
)
 
—

 
(3
)
Transfers out of Level 3
 
4

 
—

 
4

Ending balance at September 30, 2013
$
28

$
(94
)
$
(66
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
—

$
(7
)
$
(7
)
Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
(2
)
$
(a)

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

 
(2
)
Purchases
 
(2
)
 
(a)

 
(2
)
Settlements
 
1

 
(a)

 
1

Ending balance at September 30, 2013
$
(5
)
$
(a)

$
(5
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
(2
)
$
(a)

$
(2
)
(a)
Not applicable.
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level, but were recategorized to Level 3, because the inputs to the model became unobservable during the period or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers between Level 2 and Level 3 for power derivatives were primarily caused by changes in availability of financial trades observable on electronic exchanges between the periods shown below. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the three and nine months ended September 30, 2014, and 2013, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. For the three and nine months ended September 30, 2014 there were no transfers between Level 2 and Level 3 related to derivative commodity contracts. For the three months ended September 30, 2013 there were $(1) million of transfers out of Level 2 into Level 3 related to power contracts at Ameren and Ameren Missouri. For the nine months ended September 30, 2013 there were $(3) million of transfers out of Level 2 into Level 3 and $4 million of transfers into Level 2 out of Level 3 related to power contracts at Ameren and Ameren Missouri.
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, capital lease obligations and preferred stock at September 30, 2014, and December 31, 2013:
  
September 30, 2014
 
December 31, 2013
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Ameren:(a)
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
5,944

 
$
6,647

 
$
6,038

 
$
6,584

Preferred stock
142

 
122

 
142

 
118

Ameren Missouri:
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
4,004

 
$
4,466

 
$
3,757

 
$
4,124

Preferred stock
80

 
73

 
80

 
71

Ameren Illinois:
 
 
 
 
 
 
 
Long-term debt
$
1,940

 
$
2,181

 
$
1,856

 
$
2,028

Preferred stock
62

 
49

 
62

 
47

(a)
Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet.
Related Party Transactions
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS
Ameren (parent) 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 power purchases and sales, services received or rendered, and borrowings and lendings.
Transactions between affiliates are reported as intercompany transactions on their respective 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 and the money pool arrangements discussed in Note 3 - Short-term Debt and Liquidity of this report.
Electric Power Supply Agreements
In 2014, Ameren Illinois used an RFP process, administered by the IPA, to procure energy products that will settle physically from December 1, 2014, through May 31, 2017. Ameren Missouri was among the winning suppliers in the energy product RFP process. As a result, in 2014, Ameren Missouri and Ameren Illinois entered into energy product agreements by which Ameren Missouri agreed to sell and Ameren Illinois agreed to purchase 168,400 megawatthours at an average price of $51 per megawatthour during the period of January 1, 2015, through February 28, 2017.

The following table presents the impact on Ameren Missouri and Ameren Illinois of related party transactions for the three and nine months ended September 30, 2014, and 2013.
  
  
 
  
 
Three Months
 
Nine Months
Agreement
Income Statement
Line Item
 
  
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Missouri
 
Ameren
Illinois
Ameren Missouri power supply
Operating Revenues
 
2014
$
2

$
(a)

$
5

$
(a)

agreements with Ameren Illinois
 
 
2013
 
(b)

 
(a)

 
1

 
(a)

Ameren Missouri and Ameren Illinois
Operating Revenues
 
2014
 
6

 
(b)

 
15

 
1

rent and facility services
 
 
2013
 
4

 
(b)

 
16

 
1

Ameren Missouri and Ameren Illinois
Operating Revenues
 
2014
 
(b)

 
(b)

 
1

 
(b)

miscellaneous support services
 
 
2013
 
1

 
(b)

 
1

 
2

Total Operating Revenues
 
 
2014
$
8

$
(b)

$
21

$
1

 
 
 
2013
 
5

 
(b)

 
18

 
3

Ameren Illinois power supply
Purchased Power
 
2014
$
(a)

$
2

$
(a)

$
5

agreements with Ameren Missouri
 
 
2013
 
(a)

 
(b)

 
(a)

 
1

Ameren Illinois transmission
Purchased Power
 
2014
 
(a)

 
1

 
(a)

 
2

services with ATXI
 
 
2013
 
(a)

 
1

 
(a)

 
2

Total Purchased Power
 
 
2014
$
(a)

$
3

$
(a)

$
7

 
 
 
2013
 
(a)

 
1

 
(a)

 
3

  
  
 
  
 
Three Months
 
Nine Months
Agreement
Income Statement
Line Item
 
  
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Missouri
 
Ameren
Illinois
Ameren Services support services
Other Operations and Maintenance
 
2014
$
25

$
26

$
90

$
80

agreement
 
 
2013
 
25

 
22

 
85

 
70

Insurance premiums(c)
Other Operations and Maintenance
 
2014
 
(b)

 
(a)

 
(b)

 
(a)

 
 
 
2013
 
(b)

 
(a)

 
(b)

 
(a)

Total Other Operations and
 
 
2014
$
25

$
26

$
90

$
80

Maintenance Expenses
 
 
2013
 
25

 
22

 
85

 
70

Money pool borrowings (advances)
Interest Charges
 
2014
$
(b)

$
(b)

$
(b)

$
(b)

 
 
 
2013
 
(b)

 
(b)

 
(b)

 
(b)

(a)
Not applicable.
(b)
Amount less than $1 million.
(c)
Represents insurance premiums paid to Missouri Energy Risk Assurance Company LLC, 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, authorities and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in 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, Note 15 - Commitments and Contingencies, and Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions, Note 10 - Callaway Energy Center, and Note 12 - Divestiture Transactions and Discontinued Operations in this report.
Callaway Energy Center
The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at September 30, 2014. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year. Both coverages were renewed in 2014.
Type and Source of Coverage
Maximum  Coverages
 
Maximum Assessments
for Single Incidents
 
Public liability and nuclear worker liability:
 
 
 
 
American Nuclear Insurers
$
375

  
$
—

  
Pool participation
13,241

(a) 
128

(b) 
 
$
13,616

(c) 
$
128

  
Property damage:
 
 
 
 
NEIL
$
2,250

(d) 
$
23

(e) 
European Mutual Association for Nuclear Insurance
500

(f) 
—

 
 
$
2,750

 
$
23

 
Replacement power:
 
 
 
 
NEIL
$
490

(g) 
$
9

(e) 
Missouri Energy Risk Assurance Company LLC
64

(h) 
—

  
(a)
Provided through mandatory participation in an industrywide retrospective premium assessment program.
(b)
Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $19 million per year.
(c)
Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $128 million per incident for each licensed reactor it operates with a maximum of $19 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d)
NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance.
(e)
All NEIL insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.
(f)
European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage provided by NEIL.
(g)
Provides replacement power cost insurance in the event of a prolonged accidental outage. 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. Nonradiation events are sub-limited to $327.6 million.
(h)
Provides replacement power cost insurance in the event of a prolonged accidental outage. The coverage commences after the first 52 weeks of insurance coverage from NEIL concludes and is a weekly indemnity of up to $0.9 million 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 8 - Related Party Transactions for more information on this affiliate transaction.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear energy center. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment was 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 the Price-Anderson Act.
Losses resulting from terrorist attacks on nuclear facilities are covered under NEIL’s policies, subject to an industrywide aggregate policy limit of $3.24 billion, or $1.83 billion, for events not involving radiation contamination 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. The table below presents our estimated fuel, purchased power, and other commitments at September 30, 2014. Ameren’s and Ameren Missouri’s purchased power commitments include a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services at September 30, 2014. In addition, the Other column includes Ameren's and Ameren Missouri's obligations related to customer energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order. Ameren Missouri expects to incur costs of $17 million during the remainder of 2014 and $64 million in 2015 for these customer energy efficiency programs.
 
Coal
 
Natural
Gas(a)
 
Nuclear
Fuel
 
Purchased
Power(b)
 
Methane
Gas
 
Other
 
Total
Ameren:(c)
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
$
151

 
$
93

 
$
62

 
$
62

 
$
1

 
$
88

 
$
457

2015
635

 
225

 
56

 
190

 
3

 
156

 
1,265

2016
659

 
127

 
69

 
105

 
4

 
76

 
1,040

2017
682

 
80

 
59

 
66

 
4

 
50

 
941

2018
111

 
41

 
61

 
55

 
5

 
51

 
324

Thereafter
114

 
101

 
179

 
645

 
91

 
350

 
1,480

Total
$
2,352

 
$
667

 
$
486

 
$
1,123

 
$
108

 
$
771

 
$
5,507

Ameren Missouri:
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
$
151

 
$
16

 
$
62

 
$
4

 
$
1

 
$
60

 
$
294

2015
635

 
39

 
56

 
21

 
3

 
110

 
864

2016
659

 
21

 
69

 
21

 
4

 
39

 
813

2017
682

 
13

 
59

 
21

 
4

 
26

 
805

2018
111

 
8

 
61

 
21

 
5

 
27

 
233

Thereafter
114

 
29

 
179

 
120

 
91

 
183

 
716

Total
$
2,352

 
$
126

 
$
486

 
$
208

 
$
108

 
$
445

 
$
3,725

Ameren Illinois:
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
$
—

 
$
77

 
$
—

 
$
58

 
$
—

 
$
9

 
$
144

2015
—

 
186

 
—

 
169

 
—

 
28

 
383

2016
—

 
106

 
—

 
84

 
—

 
24

 
214

2017
—

 
67

 
—

 
45

 
—

 
24

 
136

2018
—

 
33

 
—

 
34

 
—

 
24

 
91

Thereafter
—

 
72

 
—

 
525

 
—

 
167

 
764

Total
$
—

 
$
541

 
$
—

 
$
915

 
$
—

 
$
276

 
$
1,732

(a)
Includes amounts for generation and for distribution.
(b)
The purchased power amounts for Ameren and Ameren Illinois include twenty-year agreements for renewable energy credits that were entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.
(c)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
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, discharges to water, water usage, impacts to air, land, and water, and chemical and waste handling. Complex and lengthy processes are required to obtain and renew approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials require release prevention plans and emergency response procedures.
The EPA is developing and implementing environmental regulations that will have a significant impact on the electric utility industry. Over time, compliance with these regulations could be costly for certain companies, including Ameren Missouri, that operate coal-fired energy centers. Significant new rules proposed or promulgated include the regulation of CO2 emissions from existing energy centers through the proposed Clean Power Plan and from new energy centers through the NSPS; revised national ambient air quality standards for ozone, fine particulates, SO2, and NOx emissions; the CSAPR, which requires further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new effluent standards applicable to waste water discharges from energy centers and new regulations under the Clean Water Act that could require significant capital expenditures, such as modifications to water intake structures or new cooling towers at Ameren Missouri’s energy centers. These new and proposed regulations, if adopted, are likely to be challenged through litigation, so their ultimate implementation, as well as the timing of any such implementation, is uncertain. Although many details of the future regulations are unknown, the combined effects of the new and proposed environmental regulations could result in significant capital expenditures and increased operating costs for Ameren and Ameren Missouri. Compliance with these environmental laws and regulations could be prohibitively expensive, result in the closure or alteration of the operation of some of Ameren Missouri’s energy centers, or require capital investment. Ameren and Ameren Missouri expect these costs would be recoverable through rates, subject to MoPSC prudence review, but the nature and timing of costs, as well as the applicable regulatory framework, could result in regulatory lag.
As of September 30, 2014, Ameren and Ameren Missouri estimate capital expenditure investments of $325 million to $375 million through 2018 to comply with existing environmental regulations. This estimate assumes that CCR will continue to be regulated as nonhazardous. Considerable uncertainty remains in this estimate. The actual amount of capital investments required to comply with existing environmental regulations may vary substantially from the above estimate due to uncertainty as to the precise compliance strategies that will be used and their ultimate cost, among other things. This estimate does not include the impacts of the proposed Clean Power Plan’s reduction in emissions of CO2, which is discussed below.
Ameren Missouri's current plan for compliance with existing environmental regulations for air emissions includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. Ameren Missouri has two scrubbers at its Sioux energy center, which are used to reduce SO2 emissions and other pollutants. Ameren Missouri's compliance plan assumes electrostatic precipitator upgrades at the Labadie energy center and the installation of additional controls including mercury control technology at multiple energy centers within its coal-fired fleet through 2018. However, Ameren Missouri is evaluating its operations and options to determine how to comply with the CSAPR, the MATS, and other recently finalized or proposed EPA regulations. Ameren Missouri may be required to install additional pollution controls within the next six to ten years. As the Clean Power Plan is still subject to revision by the EPA and implementation by the states, Ameren Missouri has not finalized a compliance plan for the proposed rule.
The following sections describe the more significant new or proposed environmental laws and rules and environmental enforcement and remediation matters 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 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). In December 2008, the United States Court of Appeals for the District of Columbia Circuit found various aspects of the regulations to be unlawful and remanded the CAIR to the EPA for further action, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR regulations were vacated by the United States Court of Appeals for the District of Columbia Circuit. The EPA appealed to the United States Supreme Court. In April 2014, the United States Supreme Court reversed the decision of the United States Court of Appeals for the District of Columbia Circuit and upheld the CSAPR. In October 2014, the United States Court of Appeals for the District of Columbia Circuit granted the EPA’s motion to lift the stay on CSPAR. The CSPAR will become effective on January 1, 2015, for SO2 and annual NOx reductions, and on May 1, 2015, for ozone season NOx reductions, with further reductions in 2017 and in subsequent years. The EPA did not revise the emission reductions previously included in CSAPR. Ameren Missouri has already taken actions to prepare for the implementation of the CSAPR, including the installation of two scrubbers at its Sioux energy center and burning ultra-low sulfur coal. Ameren Missouri does not expect to make additional capital investments to comply with the CSAPR. However, Ameren Missouri will incur additional operations and maintenance costs to lower its emissions at one or more of its energy centers for compliance with the CSAPR. These higher operations and maintenance costs are expected to be collected from customers through the FAC or higher base rates.
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, trace metals, and hydrogen chloride emissions. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant. However, in certain cases, compliance can be achieved by averaging emissions from similar 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 were granted extensions to April 2016 to comply with the MATS.
Emission Allowances
The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, the CAIR and the CSAPR. Ameren Missouri expects to have enough allowances for 2014 to avoid making external purchases to comply with the CAIR and the acid rain program.
Ameren and Ameren Missouri are reviewing the United States Court of Appeals for the District of Columbia Circuit’s decision in October 2014 lifting the stay on the CSAPR. As discussed above, the CSAPR allowance programs will begin in 2015. Ameren Missouri expects to have sufficient allowances for 2015 to avoid making external purchases to comply with CSAPR.
Greenhouse Gas Regulation
Beginning in 2011, greenhouse gas emissions from stationary sources, such as power plants, became subject to regulation under the Clean Air Act. As a result of this action, Ameren Missouri is 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 2011 for regulating greenhouse gas emissions from stationary sources, such as power plants, through operating permits and the NSR Programs. The rule requires any source that already has an operating permit to have provisions relating to greenhouse gas emissions added to its permit upon renewal. Currently, all Ameren Missouri energy centers have operating permits that have been modified to address greenhouse gas emissions. In June 2014, the United States Supreme Court ruled that the EPA may regulate greenhouse gas emissions through operating permit processes and NSR programs at stationary sources that are already subject to those programs, but may not apply operating permit processes and NSR programs to non-stationary sources solely as a result of their greenhouse gas emissions. Ameren Missouri is currently evaluating the decision and the impact, if any, on its operations.
In June 2013, the Obama administration announced that it had directed the EPA to set CO2 emissions standards for both new and existing power plants. The EPA published proposed regulations in January 2014 that would set revised CO2 emissions standards for new power plants. The proposed standards would establish separate emissions limits for new natural gas-fired plants and new coal-fired plants. In June 2014, the EPA proposed the Clean Power Plan, which sets forth CO2 emissions standards that would be applicable to existing power plants. The proposed Clean Power Plan would require each state to develop plans to achieve CO2 emission rates that the EPA calculated for each state. The EPA believes, based on their assumptions, that the Clean Power Plan would achieve a 30% decrease in CO2 emissions from 2005 levels by 2030. The proposed rule also has interim goals of aggressively reducing CO2 emissions by 2020. The EPA expects the proposed rule will be finalized by June 2015. After the proposed rule is finalized, states will have from one to three years to develop compliance plans. States will be allowed to develop independent plans or join with other states to develop joint plans. Ameren Missouri is evaluating the proposed Clean Power Plan and the potential impact to its operations. Significant uncertainty exists regarding the standard for existing power plants as the finalized rule could be different from the proposed rule and will be subject to legal challenges, both of which may result in the amount and timing of CO2 emission reductions being revised.
Based on preliminary studies, if the proposed Clean Power Plan was to be made final, Ameren Missouri anticipates new or accelerated capital expenditures and increased fuel costs would be required to achieve compliance. As proposed, the Clean Power Plan would require the states, including Missouri and Illinois, to submit compliance plans as early as 2016. The states’ compliance plans may require Ameren Missouri to construct combined cycle gas-fired and renewable energy centers, currently estimated to cost approximately $2 billion by 2020, that Ameren Missouri believes would otherwise not be necessary to meet the energy needs of its customers. Additionally, Missouri’s implementation of the proposed rules, if adopted, could result in the closure or alteration of the operation of some of Ameren Missouri’s coal and gas-fired energy centers. Ameren Missouri expects all of these increased costs, which could begin in 2017, would be recoverable, subject to MoPSC prudence review, through substantially higher electric rates charged to its customers.
Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases may result in significant increases in capital expenditures and operating costs, which could lead to increased liquidity needs and higher financing costs. These compliance costs could be prohibitive at some of Ameren Missouri’s energy centers, which could result in the impairment of long-lived assets if costs are not recovered through rates. Mandatory limits on the emission of greenhouse gases could increase costs for its customers or have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity if regulators delay or deny cost recovery in rates of these compliance costs. Ameren's and Ameren Missouri's earnings may benefit from increased investment to comply with greenhouse gas limitations to the extent the investments are reflected and recovered timely in rates charged to customers.
NSR and Clean Air Litigation
In January 2011, the Department of Justice, on behalf of the EPA, filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint, as amended in October 2013, alleges that in performing projects at its Rush Island coal-fired energy center in 2007 and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the district court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for unspecified injunctive relief remain. Ameren Missouri believes its defenses are meritorious and will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.
Ultimate resolution of this matter could have a material adverse effect 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 August 2014, the EPA published the final rule applicable to cooling water intake structures at existing power plants. The rule requires a case-by-case evaluation and plan for reducing the mortality of aquatic organisms impinged on the facility’s intake screens or entrained through the plant's cooling water system. Implementation of this rule will be administered through each power plant’s water discharge permitting process. All coal-fired and nuclear energy centers at Ameren Missouri are subject to this rule. The rule could have an adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers or extensive modifications to the cooling water systems at our energy centers and if those investments are not recovered timely in electric rates charged to our customers.
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 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 the rule is enacted as proposed, Ameren Missouri would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022. The EPA is expected to issue final guidelines by September 30, 2015.
Ash Management
In May 2010, the EPA announced proposed new regulations regarding the management and disposal of CCR, which could affect future disposal and handling costs for CCR at Ameren Missouri’s coal-fired 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 CCR without classifying it as waste. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric power plants would apply to ash ponds and CCR management and that it intended to align the effluent limitations with the CCR rules when finalized. The EPA is expected to issue regulations describing how it will regulate CCR by December 2014. Ameren Missouri is evaluating the proposed regulations to determine whether the current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren Missouri is evaluating the potential compliance costs associated with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.
Remediation
We are involved in a number of remediation actions to clean up sites impacted by hazardous substances as required by federal and state law. Such laws 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 at several contaminated sites.
As of September 30, 2014, Ameren Missouri had completed remediation at the last remaining former MGP site for which remediation was required. Ameren Missouri does not have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with former MGP sites.
As of September 30, 2014, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These sites are in various stages of investigation, evaluation, remediation, and closure. Based on current estimated plans, Ameren 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 remediation cost rate riders. To be recoverable, such costs must be prudently incurred and are subject to annual review by the ICC. As of September 30, 2014, Ameren Illinois estimated the obligation related to these former MGP sites at $254 million to $316 million. Ameren and Ameren Illinois recorded a liability of $254 million to represent their estimated minimum obligation for these sites, as no other amount within the range was a better estimate.
The scope and extent to which these former MGP sites are remediated may fluctuate as investigation and 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 used an off-site landfill, which Ameren Illinois did not own, in connection with the former operation of an energy center. Ameren Illinois could be required to perform certain maintenance activities associated with that landfill. As of September 30, 2014, Ameren Illinois estimated the obligation related to the landfill 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 some underground storage tanks and a water treatment plant in Illinois. As of September 30, 2014, Ameren Illinois recorded a liability of $0.7 million to represent its estimate of the obligation for these sites.
Ameren Missouri is investigating and addressing two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. While Ameren Missouri is the current owner of the site, it did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other potentially responsible parties, are performing a site investigation. As of September 30, 2014, 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. At the other federal agency-mandated cleanup site, Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility in Cape Girardeau, Missouri. A trust was established in the early 1990s by several businesses and governmental agencies to fund the investigation and cleanup of this site, which was completed in 2005. Ameren Missouri anticipates that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup, and therefore, believes it has no liability at September 30, 2014, for this site.
Ameren Missouri also participated in the investigation of various sites located in Sauget, Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, Inc. that former landfills and lagoons 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 potentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.
In December 2013, the EPA issued its record of decision for Sauget Area 2 approving the investigation and the remediation alternatives recommended by the potentially responsible parties. Further negotiation among the potentially responsible parties will determine how to fund the implementation of the EPA approved cleanup remedies. As of September 30, 2014, Ameren Missouri estimated its obligation related to Sauget Area 2 at $1 million to $2.5 million. Ameren Missouri recorded a liability of $1 million to represent its estimated minimum obligation for this site, 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 September 30, 2014, Ameren Missouri estimated the obligation related to the cleanup at $2.2 million to $4.5 million. Ameren Missouri recorded a liability of $2.2 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.
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.
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, Ameren Missouri claims that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In September 2014, the United States District Court for the Eastern District of Missouri ordered the case to be transferred to the United States District Court for the Southern District of New York for trial. The transfer order has been stayed pending resolution of Ameren Missouri’s request for appellate review of that order by the United States Court of Appeals for the Eight Circuit.
In June 2014, Ameren Missouri reached a settlement with another group of insurers who provided Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In accordance with the terms of that settlement, Ameren Missouri received a payment of $27 million. As of September 30, 2014, Ameren Missouri had an insurance receivable balance of $41 million and expects to ultimately collect this receivable from the remaining insurance company in the pending litigation described above. This receivable is included in “Other assets” on Ameren’s and Ameren Missouri’s balance sheets as of September 30, 2014.
Ameren's and Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if Ameren Missouri's remaining liability insurance claim is not paid.
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 at our present or former energy centers. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with the average number of parties being 81 as of September 30, 2014. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of September 30, 2014:
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Total(a)
1
 
48
 
62
 
75
(a)
Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
As of September 30, 2014, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $13 million, $5 million, and $8 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 September 30, 2014, the trust fund balance was $22 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. In August 2013, Ameren Illinois filed an appeal and a stay of the O’Fallon city administrator’s order to the Circuit Court of St. Clair County. In addition, in December 2012, the city of Peoria issued a tax liability notice alleging that Ameren Illinois failed to collect prior-period municipal taxes from certain accounts. In September 2013, a hearing officer issued an order stating that Ameren Illinois was liable to the city of Peoria for $0.5 million. Ameren Illinois filed an appeal and a stay of the order to the Circuit Court of Peoria County. Also, in late 2012, five other cities issued tax liability notices alleging that Ameren Illinois failed to collect an immaterial amount of taxes from certain accounts. Ameren Illinois believes its defenses to the allegations are meritorious. As of September 30, 2014, Ameren Illinois estimated its obligation at $2 million to $5 million. Ameren Illinois recorded a liability of $2 million, which reflects potential settlements with the Illinois cities.
Callaway Energy Center
CALLAWAY ENERGY CENTER
CALLAWAY ENERGY CENTER
Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren and other utilities that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these utilities paid the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated by those plants and sold. The NWPA also requires the DOE to review the nuclear waste fee against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren Missouri and other utilities have entered into standard contracts with the federal government. The government, represented by the DOE, is responsible for implementing these provisions of the NWPA. Consistent with the NWPA and its standard contract, Ameren Missouri has historically collected one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center. However, as described below, Ameren Missouri has suspended collection of this fee.
Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government is not meeting its disposal obligation. Ameren Missouri has sufficient installed capacity at the Callaway energy center to store its spent nuclear fuel generated through 2020, and has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s current license. 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 operations of the energy center.
In January 2009, the federal government announced that a spent nuclear fuel repository at Yucca Mountain, Nevada was unworkable. The federal government took steps to terminate the Yucca Mountain program, while acknowledging its continuing obligation to dispose of utilities’ spent nuclear fuel. In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel. The DOE's plan calls for a pilot interim storage facility to begin operation with an initial focus on accepting spent nuclear fuel from shutdown reactor sites by 2021. By 2025, a larger interim storage facility would be available, co-located with the pilot facility. The plan also proposes to site a permanent geological repository by 2026, to characterize the site and to design and to license the repository by 2042, and to begin operation by 2048.
In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit, seeking the suspension of the one mill nuclear waste fee. In November 2013, the court ordered the DOE to submit a proposal to the United States Congress to reduce the fee to zero. In January 2014, the DOE submitted a proposal to the United States Congress to reduce the fee to zero, which became effective on May 16, 2014. Since the nuclear waste fee was previously included in Ameren Missouri’s FAC, the cost reduction will be passed on to electric utility customers with no material effect on Ameren’s and Ameren Missouri’s net income.
As a result of the DOE's failure to begin to dispose of spent nuclear fuel from commercial nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have also sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs that it incurred through 2009. The lawsuit sought reimbursement for the cost of reracking the Callaway energy center’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had the DOE performed its contractual obligations. The parties entered into a settlement agreement that provides for annual recovery of additional spent fuel storage and related costs incurred from 2010 through 2016, with the ability to extend the recovery period as mutually agreed to by the parties. In March 2014, Ameren Missouri submitted its 2013 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2013 cost reimbursement of approximately $15 million during the fourth quarter of 2014. This reimbursement is included in "Miscellaneous accounts and notes receivable" on Ameren’s and Ameren Missouri’s September 30, 2014 and December 31, 2013 respective balance sheets. Included in these reimbursements are costs related to a dry spent fuel storage facility Ameren Missouri is constructing at its Callaway energy center. Ameren Missouri intends to begin transferring spent fuel assemblies to this facility in 2015. Ameren Missouri will continue to apply for reimbursement from the DOE for the cost to construct the dry spent fuel storage facility along with related allowable costs.
In December 2011, Ameren Missouri submitted a license extension application to the NRC to extend its Callaway energy center's operating license from 2024 to 2044. There is no deadline by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in approving license extensions are rules dealing with the storage of spent nuclear fuel at the reactor site and with the NRC's confidence that permanent disposal of spent nuclear fuel will be available when needed. In a June 2012 decision, the United States Court of Appeals for the District of Columbia Circuit vacated these rules and remanded the case to the NRC, holding that the NRC's obligations under the National Environmental Policy Act required a more thorough environmental analysis in support of the NRC's waste confidence decision. In June 2012, a number of groups petitioned the NRC to suspend final licensing decisions in certain NRC licensing proceedings, including the Callaway license extension, until the NRC completed its proceedings on the vacated rules. In August 2012, the NRC stated that it would not issue licenses dependent on the vacated rules until it appropriately addressed the court's remand. In September 2012, the NRC directed its staff to issue a generic environmental impact statement and a final rule to address the court's ruling. In September 2014, the NRC published its final rule and generic environmental impact statement. On October 20, 2014, the final rule became effective and the NRC lifted its suspension on final licensing decisions.
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. Amounts collected from customers are deposited into the external nuclear decommissioning trust fund to provide for the Callaway energy center’s decommissioning. 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. Annual decommissioning costs of $7 million are included in the costs of service used to establish electric rates for Ameren Missouri's customers. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. The last cost study and funding analysis was filed with the MoPSC in September 2011. The MoPSC has authorized a delay of the 2014 cost study and funding analysis filing until 2015 pending the outcome of Ameren Missouri’s operating license extension application under review by the NRC. If Ameren Missouri's operating license extension application is approved by the NRC, a revised funding analysis will be prepared, and the rates charged to customers will be adjusted accordingly to reflect the operating license extension at the time the next triennial cost study and funding analysis is approved by the MoPSC. 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 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.
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 September 30, 2014, the plan’s estimated investment performance through September 30, 2014, and Ameren’s pension funding policy, Ameren expects to make annual contributions of $40 million to $110 million in each of the next five years, with aggregate estimated contributions of $340 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 employees’ beneficiary association trusts to match the annual postretirement expense.
The following table presents the components of the net periodic benefit cost (benefit) for Ameren’s pension and postretirement benefit plans for the three and nine months ended September 30, 2014, and 2013:
  
Pension Benefits
 
Postretirement Benefits
 
 
Three Months
 
Nine Months
 
Three Months
 
Nine Months
 
  
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
Service cost
$
20

 
$
23

 
$
60

 
$
69

 
$
5

 
$
6

 
$
14

 
$
17

 
Interest cost
46

 
40

 
137

 
121

 
12

 
11

 
37

 
34

 
Expected return on plan assets
(58
)
 
(54
)
 
(172
)
 
(162
)
 
(16
)
 
(16
)
 
(48
)
 
(47
)
 
Amortization of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
(1
)
 
(1
)
 
(1
)
 
(3
)
 
(2
)
 
(1
)
 
(4
)
 
(3
)
 
Actuarial loss (gain)
13

 
23

 
37

 
69

 
(2
)
 
2

 
(5
)
 
6

 
Net periodic benefit cost (benefit)(a)
$
20

 
$
31

 
$
61

 
$
94

 
$
(3
)
 
$
2

 
$
(6
)
 
$
7

 
(a)
Includes $2 million and $8 million in total net costs for pension benefits for the three and nine months ended September 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income. Includes less than $1 million in total net costs for postretirement benefits for both the three and nine months ended September 30, 2013, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income.
Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and nine months ended September 30, 2014, and 2013:
  
Pension Benefits
 
Postretirement Benefits
 
 
Three Months
 
Nine Months
 
Three Months
 
Nine Months
 
  
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
Ameren Missouri
$
13

 
$
18

 
$
38

 
$
54

 
$ (a)

 
$
2

 
$
2

 
$
7

 
Ameren Illinois
7

 
10

 
22

 
31

 
(3
)
 
(a)

 
(7
)
 
(a)

 
Other(b)
(a)

 
3

 
1

 
9

 
(a)

 
(a)

 
(1
)
 
(a)

 
Ameren(c)
$
20

 
$
31

 
$
61

 
$
94

 
$
(3
)
 
$
2

 
$
(6
)
 
$
7

 
(a)
Less than $1 million.
(b)
Includes $2 million and $8 million in total net costs for pension benefits for the three and nine months ended September 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income. Includes less than $1 million in total net costs for postretirement benefits for both the three and nine months ended September 30, 2013, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income.
(c)
Includes amounts for Ameren registrants and nonregistrant subsidiaries.
Divestiture Transactions and Discontinued Operations (Notes)
DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS
DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS
On December 2, 2013, Ameren completed the divestiture of New AER to IPH in accordance with the transaction agreement between Ameren and IPH dated March 14, 2013, as amended by a letter agreement dated December 2, 2013. The transaction agreement with IPH, as amended, provides that if the Elgin, Gibson City, and Grand Tower gas-fired energy centers are subsequently sold by Medina Valley and if Medina Valley receives additional proceeds from such sale, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the $137.5 million previously paid to Genco.
On January 31, 2014, Medina Valley completed the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Rockland Capital for a total purchase price of $168 million, before consideration of a net working capital adjustment. The agreement with Rockland Capital required $17 million of the purchase price to be held in escrow until the two-year anniversary of the closing of the sale to fund certain indemnity obligations, if any, of Medina Valley. The Rockland Capital escrow receivable balance is reflected on Ameren's September 30, 2014, consolidated balance sheet in "Other assets." The corresponding payable due to Genco is reflected on Ameren's September 30, 2014, consolidated balance sheet in "Other deferred credits and liabilities." Medina Valley expects to pay Genco any remaining portion of the escrow balance on January 31, 2016. Ameren did not record a gain from its sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers.
Discontinued Operations Presentation
New AER and the Elgin, Gibson City, Grand Tower, Meredosia, and Hutsonville energy centers have been classified collectively in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. The disposal groups have been aggregated in the disclosures below. See Note 16 - Divestiture Transactions and Discontinued Operations under Part II, Item 8, of the Form 10-K for additional information related to disposal groups. The following table presents the components of discontinued operations in Ameren's consolidated statement of income for the three and nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
 
2014
 
2013
 
2014
 
2013
 
Operating revenues
$
—

 
$
311

 
$
1

 
$
878

 
Operating expenses
(1
)
 
(309
)
 
(4
)
 
(1,034
)
(a) 
Operating income (loss)
(1
)
 
2

 
(3
)
 
(156
)
 
Other income (loss)
—

 
—

 
—

 
(1
)
 
Interest charges
—

 
(9
)
 
—

 
(31
)
 
Loss before income taxes
(1
)
 
(7
)
 
(3
)
 
(188
)
 
Income tax (expense) benefit
—

 
4

 
—

 
(24
)
 
Loss from discontinued operations, net of taxes
$
(1
)
 
$
(3
)
 
$
(3
)
 
$
(212
)
 

(a)
Included a noncash pretax asset impairment charge of $175 million for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.
Ameren recorded a cumulative pretax charge to earnings of $175 million for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. Also, Ameren adjusted the accumulated deferred income taxes on its consolidated balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, when it became apparent that the temporary difference would reverse. For the nine months ended September 30, 2013, this change in basis resulted in a cumulative discontinued operations deferred tax expense of $96 million. The deferred tax expense was partially offset by the then-expected tax benefits of $72 million related to the pretax loss from discontinued operations including the impairment charge recorded during the nine months ended September 30, 2013.
Ameren’s results of operations for the nine months ended September 30, 2014, include adjustments for the New AER net working capital amount owed to IPH and for certain contingent liabilities associated with the New AER divestiture. The final working capital adjustment and a portion of the contingent liabilities were paid to IPH in the third quarter of 2014, resulting in a $13 million cash payment. Additionally, Ameren recognized the operating revenues and operating expenses associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers prior to the completion of their sale to Rockland Capital on January 31, 2014. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction with IPH are dependent upon 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 ultimately realized in discontinued operations may differ materially from those recorded as of September 30, 2014.
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 September 30, 2014, and December 31, 2013:
 
September 30, 2014
 
December 31, 2013
Assets of discontinued operations
 
 
 
Cash and cash equivalents
$
—

 
$
—

Accounts receivable and unbilled revenue
—

 
5

Materials and supplies
—

 
5

Property and plant, net
—

 
142

Accumulated deferred income taxes, net(a)
15

 
13

Total assets of discontinued operations
$
15

 
$
165

Liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
$
1

 
$
5

Asset retirement obligations(b)
32

 
40

Total liabilities of discontinued operations
$
33

 
$
45


(a)
Includes income tax assets related to the abandoned Meredosia and Hutsonville energy centers.
(b)
Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $32 million and $31 million at September 30, 2014, and December 31, 2013, respectively.
Pursuant to the IPH transaction agreement, as amended, Ameren is obligated to pay up to $29 million for certain contingent liabilities as of September 30, 2014, which were included in "Other deferred credits and liabilities" on Ameren's September 30, 2014 consolidated balance sheet.
The note receivable from Marketing Company related to the cash collateral support provided to New AER was $23 million and $18 million at September 30, 2014, and December 31, 2013, respectively, and was reflected on Ameren's consolidated balance sheet in "Other assets." This receivable is due to Ameren, with interest, on December 2, 2015, or sooner as cash collateral requirements are reduced. In addition, as of September 30, 2014, if Ameren’s credit ratings had been below investment grade, Ameren could have been required to post additional cash collateral in support of New AER in the amount of $23 million, which includes $4 million currently covered by Ameren guarantees. This cash collateral support is part of Ameren’s obligation to provide certain limited credit support to New AER until December 2, 2015, as discussed below.
Ameren Guarantees and Letters of Credit
The IPH transaction agreement, as amended, requires Ameren to maintain its financial obligations with respect to all credit support provided to New AER as of the December 2, 2013 closing date of the divestiture. Ameren must also provide such additional credit support as required by contracts entered into prior to the closing date, in each case until December 2, 2015. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH's indemnification obligation is secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren pursuant to which Dynegy will, among other things, guarantee IPH's indemnification obligations until December 2, 2015.
In addition to the $29 million of contingent liabilities recorded on Ameren’s September 30, 2014 consolidated balance sheet, Ameren had a total of $141 million in guarantees outstanding for New AER that were not recorded on Ameren’s September 30, 2014 consolidated balance sheet, which included:
•
$132 million related to guarantees supporting Marketing Company for physically and financially settled power transactions with its counterparties that were in place at the December 2, 2013 closing of the divestiture, as well as for Marketing Company's clearing broker and other service agreements. If Marketing Company did not fulfill its obligations to these counterparties who had active open positions as of September 30, 2014, Ameren would have been required under its guarantees to provide $4 million to the counterparties.
•
$9 million related to requirements for lease agreements and potential environmental obligations. If New AER had not fulfilled its lease obligation as of September 30, 2014, Ameren would have been required to provide approximately $8 million to the leasing counterparty.
Additionally, at September 30, 2014, Ameren had issued letters of credit totaling $9 million as credit support on behalf of New AER.
Ameren has not recorded a reserve for these contingent obligations because it does not believe a payment with respect to any of these guarantees or letters of credit was probable as of September 30, 2014.
Segment Information
SEGMENT INFORMATION
SEGMENT INFORMATION
Ameren has two reportable segments: Ameren Missouri and Ameren Illinois. The Ameren Missouri segment for both Ameren and Ameren Missouri includes all of 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 category called Other primarily includes Ameren (parent) activities, Ameren Services, and ATXI. In 2013, the Other category also included certain corporate activities previously included in the Merchant Generation segment.
The following table presents information about the reported revenues and specified items reflected in Ameren’s net income attributable to Ameren Corporation from continuing operations for the three and nine months ended September 30, 2014, and 2013, and total assets of continuing operations as of September 30, 2014, and December 31, 2013.
Three Months
Ameren
Missouri
 
Ameren
Illinois
 
Other
 
Intersegment
Eliminations
 
Ameren
 
2014
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,089

 
$
572

 
$
9

  
$
—

 
$
1,670

 
Intersegment revenues
8

 
—

 
2

  
(10
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
222

 
75

 
(3
)
 
—

 
294

 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,088

 
$
547

 
$
3

 
$
—

 
$
1,638

 
Intersegment revenues
5

 
—

 
1

 
(6
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
238

 
77

 
(10
)
 
—

 
305

 
Nine Months
  
 
  
 
  
 
  
 
  
 
2014
 
 
 
 
 
 
 
 
 
 
External revenues
$
2,793

 
$
1,864

 
$
26

 
$
—

 
$
4,683

 
Intersegment revenues
21

 
1

 
3

 
(25
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
395

 
156

 
(10
)
 
—

 
541

 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
2,760

 
$
1,744

 
$
12

 
$
—

 
$
4,516

 
Intersegment revenues
18

 
3

 
2

 
(23
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
362

 
139

 
(37
)
 
—

 
464

 
As of September 30, 2014:
 
 
 
 
 
 
 
 
 
 
Total assets
$
13,179

 
$
7,983

 
$
810

 
$
(111
)
 
$
21,861

(a) 
As of December 31, 2013:
 
 
 
 
 
 
 
 
 
 
Total assets
$
12,904

 
$
7,454

 
$
752

 
$
(233
)
 
$
20,877

(a) 
(a)    Excludes total assets from discontinued operations of $15 million and $165 million as of September 30, 2014, and December 31, 2013, respectively.
Summary Of Significant Accounting Policies (Policies)
Consolidation 
The financial statements of Ameren are prepared on a consolidated basis, and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. 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 
Basic earnings per share is computed by dividing net income attributable to Ameren Corporation common stockholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common stockholders by the diluted weighted-average number of common shares outstanding during the period. Diluted earnings per share reflects the potential dilution that would occur if certain stock-based performance share units were settled.
Stock-based Compensation 
Ameren’s long-term incentive plan available for eligible employees and directors, the 2006 Incentive Plan, was replaced prospectively for new grants by the 2014 Incentive Plan effective April 24, 2014. The 2014 Incentive Plan provides for a maximum of 8 million common shares to be available for grant to eligible employees and directors, and retains many of the features of the 2006 Incentive Plan. To the extent that the issuance of a share that is subject to an outstanding award under the 2006 Incentive Plan, as of April 24, 2014, would cause Ameren to exceed the maximum authorized shares under the 2006 Incentive Plan, the issuance of that share will take place under the 2014 Incentive Plan and will therefore reduce the maximum number of shares that may be granted under the 2014 Incentive Plan. The 2014 Incentive Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.
Intangible Assets 
Ameren and Ameren Missouri classify renewable energy credits and emission allowances as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. Ameren Missouri’s emission allowances are allocated by the EPA and therefore are recorded at zero cost. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.
At September 30, 2014, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book values of both Ameren’s and Ameren Missouri’s renewable energy credits were $20 million and $22 million at September 30, 2014 and December 31, 2013, respectively.
Ameren Missouri’s and Ameren Illinois’ renewable energy credits and Ameren Missouri’s emission allowances are charged to “Purchased power” expense and “Fuel” expense, respectively, as they are used in operations.
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 customer and are therefore not included in revenues and expenses. They are included in “Taxes accrued” on the balance sheet.
Uncertain Tax Positions 
With the adoption of new accounting guidance in the first quarter of 2014, unrecognized tax benefits are recorded as a reduction to the deferred tax assets for net operating losses and tax credit carryforwards within “Accumulated deferred income taxes, net” on our balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities” on our balance sheets.
Ameren’s federal income tax returns for the years 2011 and 2012 are before the Appeals Office of the IRS. It is reasonably possible that a settlement will be reached with the Appeals Office of the IRS in the next 12 months for the years 2011 and 2012. The potential settlement, which would primarily relate to uncertain tax positions associated with the timing of research tax deductions, is expected to result in a decrease in Ameren’s uncertain tax benefits of $6 million, all of which relates to Ameren Missouri and none of which will have a material impact on their respective results of operations or liquidity.
Ameren’s federal income tax return for the year 2013 is currently under examination by the IRS and it is reasonably possible that a settlement will be reached with the IRS examination team in the next 12 months for that year. The potential settlement, which would relate to the timing of research tax deductions and the tax basis of certain leases related to the divestiture of the merchant generation business, is expected to result in a decrease in Ameren’s uncertain tax benefits of $73 million, of which $17 million relates to Ameren Missouri and $1 million relates to Ameren Illinois. Although we are unable to estimate the impact of any potential settlement at this time, up to $55 million of the Ameren total could increase net income from Ameren’s discontinued operations. Settlement of the remaining $18 million of uncertain tax positions at Ameren, as well as those positions at Ameren Missouri and Ameren Illinois, are associated with the timing of deductions and will not have a material impact on our results of operations.
In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of our unrecognized tax benefits to fluctuate. However, other than as described above, we do not believe any such fluctuations would be material to our 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. We 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.
Asset Retirement Obligations 
AROs at Ameren, Ameren Missouri and Ameren Illinois increased at September 30, 2014, compared to December 31, 2013, to reflect the accretion of obligations to their fair value and an additional ARO at Ameren and Ameren Missouri of $2 million related to the retirement costs for a CCR storage facility, partially offset by immaterial settlements.
Noncontrolling Interest 
As of September 30, 2014, Ameren's noncontrolling interests were composed of the preferred stock not subject to mandatory redemption of Ameren Missouri and Ameren Illinois. All noncontrolling interests are 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 or issued authoritative accounting guidance relevant to the Ameren Companies.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued additional authoritative accounting guidance to provide clarity for the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. 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. This guidance was effective for the Ameren Companies beginning in the first quarter of 2014. Previously, unrecognized tax benefits were recorded in “Other deferred credits and liabilities” on Ameren's, Ameren Missouri's and Ameren Illinois' respective balance sheets. Beginning in the first quarter 2014, unrecognized tax benefits are recorded as a reduction to the deferred tax assets for net operating losses and tax credit carryforwards within “Accumulated deferred income taxes, net” on our balance sheets. Unrecognized tax benefits that exceed these carryforwards are recorded in “Other deferred credits and liabilities,” on the respective balance sheets. For comparative purposes, the Ameren Companies reclassified the December 31, 2013 balances in accordance with the new guidance as discussed in the Uncertain Tax Positions section above. The implementation of the additional authoritative accounting guidance did not affect the Ameren Companies' results of operations or liquidity, as this guidance is presentation-related only.
Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
In April 2014, FASB issued authoritative accounting guidance that changes the criteria for reporting and qualifying for discontinued operations. Under the new guidance, a component of an entity, or a group of components of an entity, that either meets the criteria to be classified as held for sale or is disposed of by sale or otherwise, is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. The guidance includes expanded disclosure requirements for discontinued operations and additional disclosures about a disposal of an individually significant component of an entity that does not qualify for discontinued operations presentation. The guidance will be effective for the Ameren Companies in the first quarter of 2015 for components that are classified as held for sale or disposed of on or after January 1, 2015. Early adoption is permitted, but only for disposals or classifications as held for sale that have not been reported in financial statements previously issued. Therefore, Ameren’s existing discontinued operations would not be subject to the new disclosure requirements. The guidance will not affect the Ameren Companies’ results of operations, financial position, or liquidity, as this guidance is presentation-related only.
Revenue from Contracts with Customers
In May 2014, FASB issued authoritative accounting guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for GAAP. The guidance requires an entity to recognize an amount of revenue for the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance also requires additional disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The guidance will be effective for the Ameren Companies in the first quarter of 2017. The Ameren Companies are currently assessing the impacts of this guidance.
Derivative Financial Instruments Derivative Financial Instruments (Policies)
Derivatives
We use derivatives to manage the risk of changes in market prices for natural gas, 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 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 September 30, 2014, the plan’s estimated investment performance through September 30, 2014, and Ameren’s pension funding policy, Ameren expects to make annual contributions of $40 million to $110 million in each of the next five years, with aggregate estimated contributions of $340 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 employees’ beneficiary association trusts to match the annual postretirement expense.
Summary Of Significant Accounting Policies (Tables)
Schedule of Earnings Per Share, Basic and Diluted 
The following table presents Ameren’s basic and diluted earnings per share calculations and reconciles the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for the three and nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
2014
 
2013
 
2014
 
2013
Net income (loss) attributable to Ameren Corporation:
 
 
 
 
 
 
 
Continuing operations
$
294

 
$
305

 
$
541

 
$
464

Discontinued operations
(1
)
 
(3
)
 
(3
)
 
(212
)
Net income attributable to Ameren Corporation
$
293

 
$
302

 
$
538

 
$
252

 
 
 
 
 
 
 
 
Average common shares outstanding - basic
242.6

 
242.6

 
242.6

 
242.6

Assumed settlement of performance share units
1.7

 
2.5

 
1.7

 
1.8

Average common shares outstanding - diluted
244.3

 
245.1

 
244.3

 
244.4

 
 
 
 
 
 
 
 
Earnings (loss) per common share – basic:
 
 
 
 
 
 
 
Continuing operations
$
1.21

 
$
1.26

 
$
2.23

 
$
1.92

Discontinued operations
—

 
(0.01
)
 
(0.01
)
 
(0.88
)
Earnings per common share – basic
$
1.21

 
$
1.25

 
$
2.22

 
$
1.04

 
 
 
 
 
 
 
 
Earnings (loss) per common share – diluted:
 
 
 
 
 
 
 
Continuing operations
$
1.20

 
$
1.25

 
$
2.21

 
$
1.91

Discontinued operations
—

 
(0.01
)
 
(0.01
)
 
(0.88
)
Earnings per common share – diluted
$
1.20

 
$
1.24

 
$
2.20

 
$
1.03

Summary Of Nonvested Shares Related To Long-Term Incentive Plan 
A summary of nonvested performance share units at September 30, 2014, and changes during the nine months ended September 30, 2014, under the 2006 Incentive Plan and the 2014 Incentive Plan are presented below:
 
Performance Share Units
 
Share Units
Weighted-average Fair Value Per Share Unit at Grant Date
Nonvested at January 1, 2014
1,218,544

$
33.23

Granted(a)
685,026

38.90

April Grants(b)
38,559

50.34

Forfeitures
(65,847
)
33.82

Vested(c)
(123,295
)
38.64

Nonvested at September 30, 2014
1,752,987

$
35.42

(a)
Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 under the 2006 Incentive Plan and the 2014 Incentive Plan.
(b)
In April 2014, certain executive officers were granted additional share units under the 2006 Incentive Plan and the 2014 Incentive Plan. The significant assumptions used to calculate fair value included a prorated three-year risk-free rate ranging from 0.76% to 0.79%, volatility of 12% to 18% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period.
(c)
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 nine months ended September 30, 2014, and 2013:
 
 
Three Months
 
Nine Months
 
2014
 
2013
 
2014
 
2013
Ameren Missouri
$
1

 
$
—

 
$
7

 
$
(a)

Ameren Illinois
 
1

 
 
2

 
 
7

 
 
9

Ameren
$
2

 
$
2

 
$
14

 
$
9

(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 nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
2014
 
2013
 
2014
 
2013
Ameren Missouri
$
47

 
$
49

 
$
120

 
$
120

Ameren Illinois
9

 
10

 
46

 
43

Ameren
$
56

 
$
59

 
$
166

 
$
163

Schedule of Unrecognized Tax Benefits 
The following table presents the total amount of reserves for unrecognized tax benefits (detriments) related to uncertain tax positions as of September 30, 2014, and December 31, 2013:
 
September 30, 2014
 
December 31,
2013
Ameren
$
97

 
$
90

Ameren Missouri
35

 
31

Ameren Illinois
1

 
(1
)
Schedule of Unrecognized Tax Benefits That Would Impact Effective Tax Rate 
The following table presents the amount of reserves for unrecognized tax benefits, included in the table above, related to uncertain tax positions that would impact results of operations, if recognized, as of September 30, 2014, and December 31, 2013:
 
September 30, 2014
 
December 31,
2013
Ameren
$
55

 
$
54

Ameren Missouri
3

 
3

Ameren Illinois
—

 
—

Equity Changes Attributable To Noncontrolling Interest 
A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three and nine months ended September 30, 2014, and 2013, are shown below:
  
Three Months
 
Nine Months
 
  
2014
 
2013
 
2014
 
2013
 
Noncontrolling interests, beginning of period
$
142

 
$
151

(a) 
$
142

 
$
151

(a) 
Net income from continuing operations attributable to noncontrolling interests
2

 
2

 
5

 
5

 
Dividends paid to noncontrolling interest holders
(2
)
 
(2
)
 
(5
)
 
(5
)
 
Noncontrolling interests, end of period
$
142

 
$
151

(a) 
$
142

 
$
151

(a) 
(a)
Included the 20% EEI ownership interest not owned by Ameren prior to the divestiture of New AER to IPH. Prior to the divestiture of New AER, the assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Assets of discontinued operations” and “Liabilities of discontinued operations,” respectively. The divestiture of New AER, which included EEI, was completed in the fourth quarter of 2013. See Note 12 - Divestiture Transactions and Discontinued Operations for additional information.
Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Tables)
Schedule of Short-term Debt [Table Text Block]
The following table presents commercial paper outstanding at Ameren (parent), Ameren Missouri and Ameren Illinois as of September 30, 2014, and December 31, 2013. Ameren Illinois established a commercial paper program in May 2014.
  
September 30, 2014
 
December 31, 2013
Ameren (parent)
$
499

 
$
368

Ameren Missouri
65

 
—

Ameren Illinois
189

 
—

Ameren Consolidated
$
753

 
$
368

The following table summarizes the commercial paper activity and relevant interest rates under Ameren’s (parent), Ameren Missouri’s and Ameren Illinois’ commercial paper programs for the nine months ended September 30, 2014, and 2013:
 
 
Ameren (parent)
Ameren Missouri
Ameren Illinois
Ameren Consolidated
2014
 
 
 
 
 
 
Average daily commercial paper outstanding
 
$
386

 
$
141

$
157

$
609

Weighted-average interest rate
 
0.36
%
 
0.38
%
0.31
%
0.35
%
Peak commercial paper during period(a)
 
$
531

 
$
495

$
300

$
907

Peak interest rate
 
0.75
%
 
0.70
%
0.34
%
0.75
%
2013
 
 
 
 
 
 
Average daily commercial paper outstanding
 
$
26

 
$
—

$
—

$
26

Weighted-average interest rate
 
0.52
%
 
—
%
—
%
0.52
%
Peak commercial paper during period(a)
 
$
92

 
$
—

$
—

$
92

Peak interest rate
 
0.85
%
 
—
%
—
%
0.85
%

(a)
The timing of peak commercial paper issuances varies by company, and therefore the peak amounts presented by company might not equal the Ameren Consolidated peak commercial paper issuances for the period.
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 September 30, 2014, at an assumed annual interest rate of 5% and dividend rate of 6%.
 
 
Required Interest
Coverage Ratio(a)
 
Actual Interest
Coverage Ratio
 
Bonds Issuable(b)
 
Required Dividend
Coverage Ratio(c)
 
Actual Dividend
Coverage Ratio
 
Preferred Stock
Issuable
 
Ameren Missouri
 
≥2.0
 
4.6
$
3,304

 
≥2.5
 
126.3
$
2,823

 
Ameren Illinois
 
≥2.0
 
6.7
 
3,636

(d) 
≥1.5
 
2.4
 
203

(e) 
(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 $833 million and $204 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.
(e)
Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation.
Debt Instrument Redemption [Table Text Block] 
In January 2014, Ameren Illinois redeemed the following environmental improvement and pollution control revenue bonds at par value plus accrued interest:
Environmental improvement and pollution control revenue bonds
Principal Amount
5.90% Series 1993 due 2023(a)
$
32

5.70% 1994A Series due 2024(a)
36

5.95% 1993 Series C-1 due 2026
35

5.70% 1993 Series C-2 due 2026
8

5.40% 1998A Series due 2028
19

5.40% 1998B Series due 2028
33

Total amount redeemed
$
163

(a)
Less than $1 million principal amount of the bonds remain outstanding after redemption.
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 for the three and nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
 
2014
 
2013
 
2014
 
2013
 
Ameren:(a)
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
10

 
$
10

 
$
26

  
$
26

 
Interest income on industrial development revenue bonds
6

 
7

 
20

  
21

 
Interest income
3

 
2

 
8

 
3

 
Other
2

 
1

 
6

 
1

 
Total miscellaneous income
$
21

 
$
20

 
$
60

  
$
51

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
3

 
$
2

 
$
9

 
$
7

 
Other
4

 
3

 
11

  
11

 
Total miscellaneous expense
$
7

 
$
5

 
$
20

  
$
18

 
Ameren Missouri:
 
 
 
 
 
 
 
 
Miscellaneous income:
 
 
 
 
 
 
 
 
Allowance for equity funds used during construction
$
9

 
$
8

 
$
24

  
$
22

 
Interest income on industrial development revenue bonds
6

 
7

 
20

 
21

 
Interest income
—

 
1

 
1

 
1

 
Total miscellaneous income
$
15

 
$
16

 
$
45

  
$
44

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
2

 
$
—

 
$
5

  
$
3

 
Other
2

 
2

 
5

  
7

 
Total miscellaneous expense
$
4

 
$
2

 
$
10

  
$
10

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

 
$
2

 
$
2

  
$
4

 
Interest income
2

 
1

 
5

  
2

 
Other
1

 
1

 
5

 
1

 
Total miscellaneous income
$
4

 
$
4

 
$
12

  
$
7

 
Miscellaneous expense:
 
 
 
 
 
 
 
 
Donations
$
—

 
$
—

 
$
3

 
$
3

 
Other
2

 
3

 
4

  
4

 
Total miscellaneous expense
$
2

 
$
3

 
$
7

  
$
7

 
(a)
Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Derivative Financial Instruments (Tables)
Open Gross Derivative Volumes By Commodity Type 
The following table presents open gross commodity contract volumes by commodity type for derivative assets and liabilities as of September 30, 2014, and December 31, 2013. As of September 30, 2014, these contracts ran through October 2017, October 2019, May 2032, and October 2016 for fuel oils, natural gas, power, and uranium, respectively.
  
Quantity (in millions, except as indicated)
 
2014
2013
Commodity
Ameren Missouri
Ameren Illinois
Ameren
Ameren Missouri
Ameren Illinois
Ameren
Fuel oils (in gallons)(a)
52

(b)

52

66

(b)

66

Natural gas (in mmbtu)
23

102

125

28

108

136

Power (in megawatthours)
1

11

12

3

11

14

Uranium (pounds in thousands)
557

(b)

557

796

(b)

796

(a)
Fuel oils consist of ultra-low-sulfur diesel, on-highway diesel, and crude oil.
(b)
Not applicable.
Derivative Instruments Carrying Value 
The following table presents the carrying value and balance sheet location of all derivative commodity contracts, none of which were designated as hedging instruments, as of September 30, 2014, and December 31, 2013:
 
Balance Sheet Location
 
Ameren  Missouri
 
Ameren  Illinois
 
Ameren
2014
 
 
 
 
 
 
Fuel oils
Other current assets
 
$
3

 
$
—

 
$
3

Natural gas
Other current assets
 
—

 
1

 
1

 
Other assets
 
—

 
1

 
1

Power
Other current assets
 
10

 
—

 
10

 
Other assets
 
1

 
—

 
1

 
Total assets
 
$
14

 
$
2

 
$
16

Fuel oils
Other current liabilities
 
$
5

 
$
—

 
$
5

 
Other deferred credits and liabilities
 
1

 
—

 
1

Natural gas
Other current liabilities
 
3

 
16

 
19

 
Other deferred credits and liabilities
 
3

 
6

 
9

Power
Other current liabilities
 
6

 
8

 
14

 
Other deferred credits and liabilities
 
—

 
116

 
116

Uranium
Other current liabilities
 
2

 
—

 
2

 
Other deferred credits and liabilities
 
1

 
—

 
1

 
Total liabilities
 
$
21

 
$
146

 
$
167

2013
 
 
 
 
 
 
Fuel oils
Other current assets
 
$
6

 
$
—

 
$
6

 
Other assets
 
3

 
—

 
3

Natural gas
Other current assets
 
1

 
1

 
2

Power
Other current assets
 
23

 
—

 
23

 
Total assets
 
$
33

 
$
1

 
$
34

Fuel oils
Other current liabilities
 
$
2

 
$
—

 
$
2

 
Other deferred credits and liabilities
 
1

 
—

 
1

Natural gas
Other current liabilities
 
5

 
27

 
32

 
Other deferred credits and liabilities
 
6

 
19

 
25

Power
Other current liabilities
 
4

 
9

 
13

 
Other deferred credits and liabilities
 
—

 
99

 
99

Uranium
Other current liabilities
 
5

 
—

 
5

 
Other deferred credits and liabilities
 
1

 
—

 
1

 
Total liabilities
 
$
24

 
$
154

 
$
178



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 as regulatory assets or regulatory liabilities as of September 30, 2014, and December 31, 2013:
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
2014
 
 
 
 
 
Fuel oils derivative contracts(a)
$
(5
)
 
$
—

 
$
(5
)
Natural gas derivative contracts(b)
(6
)
 
(20
)
 
(26
)
Power derivative contracts(c)
5

 
(124
)
 
(119
)
Uranium derivative contracts(d)
(3
)
 
—

 
(3
)
2013
 
 
 
 
 
Fuel oils derivative contracts
$
2

 
$
—

 
$
2

Natural gas derivative contracts
(10
)
 
(45
)
 
(55
)
Power derivative contracts
19

 
(108
)
 
(89
)
Uranium derivative contracts
(6
)
 
—

 
(6
)
(a)
Represents net losses associated with fuel oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2017. Current losses deferred as regulatory assets include $4 million and $4 million at Ameren and Ameren Missouri, respectively.
(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 2018 at Ameren Illinois. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively. Current losses deferred as regulatory assets include $19 million, $3 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively.
(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. Current gains deferred as regulatory liabilities include $10 million and $10 million at Ameren and Ameren Missouri. Current losses deferred as regulatory assets include $14 million, $6 million, and $8 million at Ameren, Ameren Missouri and Ameren Illinois, respectively.
(d)
Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through December 2016. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri, respectively.
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 September 30, 2014, and December 31, 2013:
 
 
 
 
Gross Amounts Not Offset in the Balance Sheet
 
 
Commodity Contracts Eligible to be Offset
 
Gross Amounts Recognized in the Balance Sheet
 
Derivative Instruments
 
Cash Collateral Received/Posted(a)
 
Net
Amount
2014
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
14

 
$
7

 
$
—

 
$
7

Ameren Illinois
 
2

 
1

 
—

 
1

Ameren
 
$
16

 
$
8

 
$
—

 
$
8

Liabilities:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
21

 
$
7

 
$
5

 
$
9

Ameren Illinois
 
146

 
1

 
—

 
145

Ameren
 
$
167

 
$
8

 
$
5

 
$
154

2013
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
33

 
$
9

 
$
—

 
$
24

Ameren Illinois
 
1

 
1

 
—

 
—

Ameren
 
$
34

 
$
10

 
$
—

 
$
24

Liabilities:
 
 
 
 
 
 
 
 
Ameren Missouri
 
$
24

 
$
9

 
$
9

 
$
6

Ameren Illinois
 
154

 
1

 
15

 
138

Ameren
 
$
178

 
$
10

 
$
24

 
$
144

(a)
Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet.
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 September 30, 2014, or December 31, 2013, 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)
2014
 
 
 
 
 
Ameren Missouri
$
62

 
$
2

 
$
57

Ameren Illinois
61

 
—

 
56

Ameren
$
123

 
$
2

 
$
113

2013
 
 
 
 
 
Ameren Missouri
$
70

 
$
2

 
$
67

Ameren Illinois
75

 
15

 
55

Ameren
$
145

 
$
17

 
$
122

(a)
Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures.
(b)
As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements.
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 September 30, 2014:
 
 
Fair Value
 
 
 
Weighted Average
 
 
Assets
Liabilities
Valuation Technique(s)
Unobservable Input
Range
Level 3 Derivative asset and liability - commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
3

$
(3
)
Option model
Volatilities(%)(b)
2 - 27
14
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.25 - 1
0.72
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
0.43
(e)
 
Natural gas
1

—

Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.10) - 0
(0.10)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.30 - 2
0.62
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
Power(f)
10

(129
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
29 - 59
35
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,853) - 2,087
199
 
 
 
 
 
Nodal basis($/MWh)(c)
(6) - 0
(3)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.40
(e)
 
 
 
 
 
Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
2
(e)
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
35 - 41
36
Ameren Missouri
Fuel oils
$
3

$
(3
)
Option model
Volatilities(%)(b)
2 - 27
14
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.25 - 1
0.72
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
0.43
(e)
 
Power(f)
10

(5
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
30 - 59
48
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,853) - 2,087
199
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.40
(e)
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
0.43
(e)
 
Uranium
—

(3
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
35 - 41
36
Ameren Illinois
Natural gas
$
1

$
—

Discounted cash flow
Nodal basis($/mmbtu)(c)
(0.10) - 0
(0.10)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.30 - 2
0.62
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
Power(f)
—

(124
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)
29 - 42
33
 
 
 
 
 
Nodal basis($/MWh)(b)
(6) - 0
(3)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
0.43
(e)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
2
(e)
 
 
 
 
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 applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.
(e)
Not applicable.
(f)
Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 use fundamentally modeled pricing by month for peak and off-peak demand.
(g)
Escalation rate applies to power prices 2026 and beyond.
The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2013:
 
 
Fair Value
 
 
 
Weighted Average
 
 
Assets
Liabilities
Valuation Technique(s)
Unobservable Input
Range
Level 3 Derivative asset and liability – commodity contracts(a):
 
 
 
Ameren
Fuel oils
$
8

$
(3
)
Option model
Volatilities(%)(b)
10 - 35
16
 
 
 
 
Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 2
1
 
Power(e)
21

(110
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
25 - 51
32
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,594) - 945
305
 
 
 
 
 
Nodal basis($/MWh)(c)
(3) - (1)
(2)
 
 
 
 
 
Counterparty credit risk(%)(c)(d)
0.39 - 0.50
0.42
 
 
 
 
 
Ameren Missouri and Ameren Illinois credit risk(%)(c)(d)
2
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
3 - 4
4
 
 


Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
 
Uranium
—

(6
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
34 - 41
36
Ameren Missouri
Fuel oils
$
8

$
(3
)
Option model
Volatilities(%)(b)
10 - 35
16
 
 


Discounted cash flow
Counterparty credit risk(%)(c)(d)
0.26 - 2
1
 
Power(e)
21

(2
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c)
25 - 51
40
 
 
 
 
 
Estimated auction price for FTRs($/MW)(b)
(1,594) - 945
305
 
 


 
Nodal basis($/MWh)(c)
(3) - (1)
(2)
 
 


 
Counterparty credit risk(%)(c)(d)
0.39 - 0.50
0.42
 
 
 
 
 
Ameren Missouri credit risk(%)(c)(d)
2
(f)
 
Uranium
—

(6
)
Discounted cash flow
Average forward uranium pricing($/pound)(b)
34 - 41
36
Ameren Illinois
Power(e)
$
—

$
(108
)
Discounted cash flow
Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b)
27 - 36
30
 
 
 
 
 
Nodal basis($/MWh)(b)
(4) - 0
(2)
 
 
 
 
 
Ameren Illinois credit risk(%)(c)(d)
2
(f)
 
 
 
 
Fundamental energy production model
Estimated future gas prices($/mmbtu)(b)
4 - 5
5
 
 
 
 
 
Escalation rate(%)(b)(g)
3 - 4
4
 
 
 
 
Contract price allocation
Estimated renewable energy credit costs($/credit)(b)
5 - 7
6
(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
(b)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(c)
Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(d)
Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances.
(e)
Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 use fundamentally modeled pricing by month for peak and off-peak demand.
(f)
Not applicable.
(g)
Escalation rate applies to power prices 2026 and beyond.
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 September 30, 2014:
 
 
 
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
 
$
—

 
$
—

 
$
3

 
$
3

 
 
Natural gas
 
—

 
1

 
1

 
2

 
 
Power
 
—

 
1

 
10

 
11

 
 
Total derivative assets - commodity contracts
 
$
—

 
$
2

 
$
14

 
$
16

 
 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
 
Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
348

 
—

 
—

 
348

 
 
Debt securities:
 
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
60

 
—

 
60

 
 
Municipal bonds
 
—

 
2

 
—

 
2

 
 
U.S. treasury and agency securities
 
—

 
100

 
—

 
100

 
 
Asset-backed securities
 
—

 
11

 
—

 
11

 
 
Other
 
—

 
5

 
—

 
5

 
 
Total nuclear decommissioning trust fund
 
$
349

 
$
178

 
$
—

 
$
527

(b) 
 
Total Ameren
 
$
349

 
$
180

 
$
14

 
$
543

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

 
$
—

 
$
3

 
$
3

 
 
Power
 
—

 
1

 
10

 
11

 
 
Total derivative assets - commodity contracts
 
$
—

 
$
1

 
$
13

 
$
14

 
 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
1

 
$
—

 
$
—

 
$
1

 
 
Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
348

 
—

 
—

 
348

 
 
Debt securities:
 
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
60

 
—

 
60

 
 
Municipal bonds
 
—

 
2

 
—

 
2

 
 
U.S. treasury and agency securities
 
—

 
100

 
—

 
100

 
 
Asset-backed securities
 
—

 
11

 
—

 
11

 
 
Other
 
—

 
5

 
—

 
5

 
 
Total nuclear decommissioning trust fund
 
$
349

 
$
178

 
$
—

 
$
527

(b) 
 
Total Ameren Missouri
 
$
349

 
$
179

 
$
13

 
$
541

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

 
$
1

 
$
1

 
$
2

 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
3

 
$
—

 
$
3

 
$
6

 
 
Natural gas
 
2

 
26

 
—

 
28

 
 
Power
 
—

 
1

 
129

 
130

 
 
Uranium
 
—

 
—

 
3

 
3

 
 
Total Ameren
 
$
5

 
$
27

 
$
135

 
$
167

 
Ameren
Derivative liabilities - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Missouri
Fuel oils
 
$
3

 
$
—

 
$
3

 
$
6

 
 
Natural gas
 
2

 
4

 
—

 
6

 
 
Power
 
—

 
1

 
5

 
6

 
 
Uranium
 
—

 
—

 
3

 
3

 
 
Total Ameren Missouri
 
$
5

 
$
5

 
$
11

 
$
21

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

 
$
22

 
$
—

 
$
22

 
 
Power
 
—

 
—

 
124

 
124

 
 
Total Ameren Illinois
 
$
—

 
$
22

 
$
124

 
$
146

 
(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, 2013:
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
or Liabilities
(Level 1)
 
Significant Other
Observable Inputs
(Level 2)
 
Significant Other
Unobservable
Inputs
(Level 3)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Ameren
Derivative assets - commodity contracts(a):
 
 
 
 
 
 
 
 
 
Fuel oils
 
$
1

 
$
—

 
$
8

 
$
9

 
Natural gas
 
—

 
2

 
—

 
2

 
Power
 
—

 
2

 
21

 
23

 
Total derivative assets - commodity contracts
 
$
1

 
$
4

 
$
29

 
$
34

 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
332

 
—

 
—

 
332

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
52

 
—

 
52

 
Municipal bonds
 
—

 
2

 
—

 
2

 
U.S. treasury and agency securities
 
—

 
94

 
—

 
94

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
335

 
$
159

 
$
—

 
$
494

 
Total Ameren
 
$
336

 
$
163

 
$
29

 
$
528

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

 
$
—

 
$
8

 
$
9

 
Natural gas
 
—

 
1

 
—

 
1

 
Power
 
—

 
2

 
21

 
23

 
Total derivative assets - commodity contracts
 
$
1

 
$
3

 
$
29

 
$
33

 
Nuclear decommissioning trust fund:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
3

 
$
—

 
$
—

 
$
3

 
Equity securities:
 
 
 
 
 
 
 
 
 
U.S. large capitalization
 
332

 
—

 
—

 
332

 
Debt securities:
 
 
 
 
 
 
 
 
 
Corporate bonds
 
—

 
52

 
—

 
52

 
Municipal bonds
 
—

 
2

 
—

 
2

 
U.S. treasury and agency securities
 
—

 
94

 
—

 
94

 
Asset-backed securities
 
—

 
10

 
—

 
10

 
Other
 
—

 
1

 
—

 
1

 
Total nuclear decommissioning trust fund
 
$
335

 
$
159

 
$
—

 
$
494

 
Total Ameren Missouri
 
$
336

 
$
162

 
$
29

 
$
527

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

 
$
1

 
$
—

 
$
1

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

 
$
—

 
$
3

 
$
3

 
Natural gas
 
3

 
54

 
—

 
57

 
Power
 
—

 
2

 
110

 
112

 
Uranium
 
—

 
—

 
6

 
6

 
Total Ameren
 
$
3

 
$
56

 
$
119

 
$
178

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

 
$
—

 
$
3

 
$
3

 
Natural gas
 
3

 
8

 
—

 
11

 
Power
 
—

 
2

 
2

 
4

 
Uranium
 
—

 
—

 
6

 
6

 
Total Ameren Missouri
 
$
3

 
$
10

 
$
11

 
$
24

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

 
$
46

 
$
—

 
$
46

 
Power
 
—

 
—

 
108

 
108

 
Total Ameren Illinois
 
$
—

 
$
46

 
$
108

 
$
154

(a)
The derivative asset and liability balances are presented net of counterparty credit considerations.
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 September 30, 2014:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
2

$
(a)

$
2

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

 
(2
)
Ending balance at September 30, 2014
$
—

$
(a)

$
—

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(2
)
$
(a)

$
(2
)
Natural gas:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
—

$
—

$
—

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

 
1

 
1

Ending balance at September 30, 2014
$
—

$
1

$
1

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
—

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
15

$
(103
)
$
(88
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(5
)
 
(23
)
 
(28
)
Settlements
 
(5
)
 
2

 
(3
)
Ending balance at September 30, 2014
$
5

$
(124
)
$
(119
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(6
)
$
(22
)
$
(28
)
Uranium:
 
 
 
 
 
 
Beginning balance at July 1, 2014
$
(7
)
$
(a)

$
(7
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
3

 
(a)

 
3

Settlements
 
1

 
(a)

 
1

Ending balance at September 30, 2014
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
3

$
(a)

$
3

(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 September 30, 2013:
  
 
Net derivative commodity contracts
Three Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
3

$
(a)

$
3

Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
1

 
(a)

 
1

Purchases
 
1

 
(a)

 
1

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(1
)
 
(a)

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

$
(a)

$
3

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

$
(a)

$
1

Natural gas:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
(1
)
$
2

$
1

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

 
(2
)
 
(2
)
Purchases
 
1

 
—

 
1

Ending balance at September 30, 2013
$
—

$
—

$
—

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

$
(1
)
$
(1
)
Power:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
37

$
(80
)
$
(43
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(3
)
 
(17
)
 
(20
)
Sales
 
1

 
—

 
1

Settlements
 
(6
)
 
3

 
(3
)
Transfers into Level 3
 
(1
)
 
—

 
(1
)
Ending balance at September 30, 2013
$
28

$
(94
)
$
(66
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
(2
)
$
(16
)
$
(18
)
Uranium:
 
 
 
 
 
 
Beginning balance at July 1, 2013
$
(3
)
$
(a)

$
(3
)
Purchases
 
(2
)
 
(a)

 
(2
)
Ending balance at September 30, 2013
$
(5
)
$
(a)

$
(5
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
(2
)
$
(a)

$
(2
)
(a)
Not applicable.
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 nine months ended September 30, 2014:
  
 
Net derivative commodity contracts
Nine Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
5

$
(a)

$
5

Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(3
)
 
(a)

 
(3
)
Settlements
 
(2
)
 
(a)

 
(2
)
Ending balance at September 30, 2014
$
—

$
(a)

$
—

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(2
)
$
(a)

$
(2
)
Natural gas:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
—

$
—

$
—

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

 
1

 
1

Purchases
 
—

 
(1
)
 
(1
)
Settlements
 
—

 
1

 
1

Ending balance at September 30, 2014
$
—

$
1

$
1

Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
—

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
19

$
(108
)
$
(89
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(23
)
 
(19
)
 
(42
)
Purchases
 
34

 
—

 
34

Settlements
 
(25
)
 
3

 
(22
)
Ending balance at September 30, 2014
$
5

$
(124
)
$
(119
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
(3
)
$
(21
)
$
(24
)
Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2014
$
(6
)
$
(a)

$
(6
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(1
)
 
(a)

 
(1
)
Settlements
 
4

 
(a)

 
4

Ending balance at September 30, 2014
$
(3
)
$
(a)

$
(3
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2014
$
—

$
(a)

$
—

(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 nine months ended September 30, 2013:
  
 
Net derivative commodity contracts
Nine Months
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Fuel oils:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
5

$
(a)

$
5

Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
(1
)
 
(a)

 
(1
)
Purchases
 
2

 
(a)

 
2

Sales
 
(1
)
 
(a)

 
(1
)
Settlements
 
(2
)
 
(a)

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

$
(a)

$
3

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

$
(a)

$
—

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

$
—

$
—

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

 
(1
)
 
(1
)
Purchases
 
—

 
1

 
1

Ending balance at September 30, 2013
$
—

$
—

$
—

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

$
—

$
—

Power:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
11

$
(111
)
$
(100
)
Realized and unrealized gains (losses) included in regulatory assets/liabilities
 
3

 
(2
)
 
1

Purchases
 
40

 
—

 
40

Sales
 
1

 
—

 
1

Settlements
 
(28
)
 
19

 
(9
)
Transfers into Level 3
 
(3
)
 
—

 
(3
)
Transfers out of Level 3
 
4

 
—

 
4

Ending balance at September 30, 2013
$
28

$
(94
)
$
(66
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
—

$
(7
)
$
(7
)
Uranium:
 
 
 
 
 
 
Beginning balance at January 1, 2013
$
(2
)
$
(a)

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

 
(2
)
Purchases
 
(2
)
 
(a)

 
(2
)
Settlements
 
1

 
(a)

 
1

Ending balance at September 30, 2013
$
(5
)
$
(a)

$
(5
)
Change in unrealized gains (losses) related to assets/liabilities held at September 30, 2013
$
(2
)
$
(a)

$
(2
)
(a)
Not applicable.
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, capital lease obligations and preferred stock at September 30, 2014, and December 31, 2013:
  
September 30, 2014
 
December 31, 2013
  
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Ameren:(a)
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
5,944

 
$
6,647

 
$
6,038

 
$
6,584

Preferred stock
142

 
122

 
142

 
118

Ameren Missouri:
 
 
 
 
 
 
 
Long-term debt and capital lease obligations (including current portion)
$
4,004

 
$
4,466

 
$
3,757

 
$
4,124

Preferred stock
80

 
73

 
80

 
71

Ameren Illinois:
 
 
 
 
 
 
 
Long-term debt
$
1,940

 
$
2,181

 
$
1,856

 
$
2,028

Preferred stock
62

 
49

 
62

 
47

(a)
Preferred stock is recorded in “Noncontrolling Interests” on the consolidated 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 nine months ended September 30, 2014, and 2013.
  
  
 
  
 
Three Months
 
Nine Months
Agreement
Income Statement
Line Item
 
  
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Missouri
 
Ameren
Illinois
Ameren Missouri power supply
Operating Revenues
 
2014
$
2

$
(a)

$
5

$
(a)

agreements with Ameren Illinois
 
 
2013
 
(b)

 
(a)

 
1

 
(a)

Ameren Missouri and Ameren Illinois
Operating Revenues
 
2014
 
6

 
(b)

 
15

 
1

rent and facility services
 
 
2013
 
4

 
(b)

 
16

 
1

Ameren Missouri and Ameren Illinois
Operating Revenues
 
2014
 
(b)

 
(b)

 
1

 
(b)

miscellaneous support services
 
 
2013
 
1

 
(b)

 
1

 
2

Total Operating Revenues
 
 
2014
$
8

$
(b)

$
21

$
1

 
 
 
2013
 
5

 
(b)

 
18

 
3

Ameren Illinois power supply
Purchased Power
 
2014
$
(a)

$
2

$
(a)

$
5

agreements with Ameren Missouri
 
 
2013
 
(a)

 
(b)

 
(a)

 
1

Ameren Illinois transmission
Purchased Power
 
2014
 
(a)

 
1

 
(a)

 
2

services with ATXI
 
 
2013
 
(a)

 
1

 
(a)

 
2

Total Purchased Power
 
 
2014
$
(a)

$
3

$
(a)

$
7

 
 
 
2013
 
(a)

 
1

 
(a)

 
3

  
  
 
  
 
Three Months
 
Nine Months
Agreement
Income Statement
Line Item
 
  
 
Ameren
Missouri
 
Ameren
Illinois
 
Ameren
Missouri
 
Ameren
Illinois
Ameren Services support services
Other Operations and Maintenance
 
2014
$
25

$
26

$
90

$
80

agreement
 
 
2013
 
25

 
22

 
85

 
70

Insurance premiums(c)
Other Operations and Maintenance
 
2014
 
(b)

 
(a)

 
(b)

 
(a)

 
 
 
2013
 
(b)

 
(a)

 
(b)

 
(a)

Total Other Operations and
 
 
2014
$
25

$
26

$
90

$
80

Maintenance Expenses
 
 
2013
 
25

 
22

 
85

 
70

Money pool borrowings (advances)
Interest Charges
 
2014
$
(b)

$
(b)

$
(b)

$
(b)

 
 
 
2013
 
(b)

 
(b)

 
(b)

 
(b)

(a)
Not applicable.
(b)
Amount less than $1 million.
(c)
Represents insurance premiums paid to Missouri Energy Risk Assurance Company LLC, 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 September 30, 2014. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year. Both coverages were renewed in 2014.
Type and Source of Coverage
Maximum  Coverages
 
Maximum Assessments
for Single Incidents
 
Public liability and nuclear worker liability:
 
 
 
 
American Nuclear Insurers
$
375

  
$
—

  
Pool participation
13,241

(a) 
128

(b) 
 
$
13,616

(c) 
$
128

  
Property damage:
 
 
 
 
NEIL
$
2,250

(d) 
$
23

(e) 
European Mutual Association for Nuclear Insurance
500

(f) 
—

 
 
$
2,750

 
$
23

 
Replacement power:
 
 
 
 
NEIL
$
490

(g) 
$
9

(e) 
Missouri Energy Risk Assurance Company LLC
64

(h) 
—

  
(a)
Provided through mandatory participation in an industrywide retrospective premium assessment program.
(b)
Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $19 million per year.
(c)
Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $128 million per incident for each licensed reactor it operates with a maximum of $19 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d)
NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance.
(e)
All NEIL insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL.
(f)
European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage provided by NEIL.
(g)
Provides replacement power cost insurance in the event of a prolonged accidental outage. 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. Nonradiation events are sub-limited to $327.6 million.
(h)
Provides replacement power cost insurance in the event of a prolonged accidental outage. The coverage commences after the first 52 weeks of insurance coverage from NEIL concludes and is a weekly indemnity of up to $0.9 million 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 8 - Related Party Transactions for more information on this affiliate transaction.
Long-term Purchase Commitment [Table Text Block] 
To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for purchased power and natural gas for distribution. The table below presents our estimated fuel, purchased power, and other commitments at September 30, 2014. Ameren’s and Ameren Missouri’s purchased power commitments include a 102-megawatt power purchase agreement with a wind farm operator, which expires in 2024. Ameren’s and Ameren Illinois’ purchased power commitments include the Ameren Illinois power purchase agreements entered into as part of the IPA-administered power procurement process. Included in the Other column are minimum purchase commitments under contracts for equipment, design and construction, and meter reading services at September 30, 2014. In addition, the Other column includes Ameren's and Ameren Missouri's obligations related to customer energy efficiency programs under the MEEIA as approved by the MoPSC's December 2012 electric rate order. Ameren Missouri expects to incur costs of $17 million during the remainder of 2014 and $64 million in 2015 for these customer energy efficiency programs.
 
Coal
 
Natural
Gas(a)
 
Nuclear
Fuel
 
Purchased
Power(b)
 
Methane
Gas
 
Other
 
Total
Ameren:(c)
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
$
151

 
$
93

 
$
62

 
$
62

 
$
1

 
$
88

 
$
457

2015
635

 
225

 
56

 
190

 
3

 
156

 
1,265

2016
659

 
127

 
69

 
105

 
4

 
76

 
1,040

2017
682

 
80

 
59

 
66

 
4

 
50

 
941

2018
111

 
41

 
61

 
55

 
5

 
51

 
324

Thereafter
114

 
101

 
179

 
645

 
91

 
350

 
1,480

Total
$
2,352

 
$
667

 
$
486

 
$
1,123

 
$
108

 
$
771

 
$
5,507

Ameren Missouri:
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
$
151

 
$
16

 
$
62

 
$
4

 
$
1

 
$
60

 
$
294

2015
635

 
39

 
56

 
21

 
3

 
110

 
864

2016
659

 
21

 
69

 
21

 
4

 
39

 
813

2017
682

 
13

 
59

 
21

 
4

 
26

 
805

2018
111

 
8

 
61

 
21

 
5

 
27

 
233

Thereafter
114

 
29

 
179

 
120

 
91

 
183

 
716

Total
$
2,352

 
$
126

 
$
486

 
$
208

 
$
108

 
$
445

 
$
3,725

Ameren Illinois:
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
$
—

 
$
77

 
$
—

 
$
58

 
$
—

 
$
9

 
$
144

2015
—

 
186

 
—

 
169

 
—

 
28

 
383

2016
—

 
106

 
—

 
84

 
—

 
24

 
214

2017
—

 
67

 
—

 
45

 
—

 
24

 
136

2018
—

 
33

 
—

 
34

 
—

 
24

 
91

Thereafter
—

 
72

 
—

 
525

 
—

 
167

 
764

Total
$
—

 
$
541

 
$
—

 
$
915

 
$
—

 
$
276

 
$
1,732

(a)
Includes amounts for generation and for distribution.
(b)
The purchased power amounts for Ameren and Ameren Illinois include twenty-year agreements for renewable energy credits that were entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits.
(c)
Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Schedule of Asbestors-Related Litigation Pending Lawsuits 
The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of September 30, 2014:
Ameren
 
Ameren
Missouri
 
Ameren
Illinois
 
Total(a)
1
 
48
 
62
 
75
(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 (benefit) for Ameren’s pension and postretirement benefit plans for the three and nine months ended September 30, 2014, and 2013:
  
Pension Benefits
 
Postretirement Benefits
 
 
Three Months
 
Nine Months
 
Three Months
 
Nine Months
 
  
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
Service cost
$
20

 
$
23

 
$
60

 
$
69

 
$
5

 
$
6

 
$
14

 
$
17

 
Interest cost
46

 
40

 
137

 
121

 
12

 
11

 
37

 
34

 
Expected return on plan assets
(58
)
 
(54
)
 
(172
)
 
(162
)
 
(16
)
 
(16
)
 
(48
)
 
(47
)
 
Amortization of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (benefit)
(1
)
 
(1
)
 
(1
)
 
(3
)
 
(2
)
 
(1
)
 
(4
)
 
(3
)
 
Actuarial loss (gain)
13

 
23

 
37

 
69

 
(2
)
 
2

 
(5
)
 
6

 
Net periodic benefit cost (benefit)(a)
$
20

 
$
31

 
$
61

 
$
94

 
$
(3
)
 
$
2

 
$
(6
)
 
$
7

 
(a)
Includes $2 million and $8 million in total net costs for pension benefits for the three and nine months ended September 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income. Includes less than $1 million in total net costs for postretirement benefits for both the three and nine months ended September 30, 2013, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income.
Summary Of Benefit Plan Costs Incurred 
Ameren Missouri and Ameren Illinois are responsible for their respective shares of Ameren’s pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and nine months ended September 30, 2014, and 2013:
  
Pension Benefits
 
Postretirement Benefits
 
 
Three Months
 
Nine Months
 
Three Months
 
Nine Months
 
  
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
Ameren Missouri
$
13

 
$
18

 
$
38

 
$
54

 
$ (a)

 
$
2

 
$
2

 
$
7

 
Ameren Illinois
7

 
10

 
22

 
31

 
(3
)
 
(a)

 
(7
)
 
(a)

 
Other(b)
(a)

 
3

 
1

 
9

 
(a)

 
(a)

 
(1
)
 
(a)

 
Ameren(c)
$
20

 
$
31

 
$
61

 
$
94

 
$
(3
)
 
$
2

 
$
(6
)
 
$
7

 
(a)
Less than $1 million.
(b)
Includes $2 million and $8 million in total net costs for pension benefits for the three and nine months ended September 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income. Includes less than $1 million in total net costs for postretirement benefits for both the three and nine months ended September 30, 2013, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income.
(c)
Includes amounts for Ameren registrants and nonregistrant subsidiaries.
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 September 30, 2014, and December 31, 2013:
 
September 30, 2014
 
December 31, 2013
Assets of discontinued operations
 
 
 
Cash and cash equivalents
$
—

 
$
—

Accounts receivable and unbilled revenue
—

 
5

Materials and supplies
—

 
5

Property and plant, net
—

 
142

Accumulated deferred income taxes, net(a)
15

 
13

Total assets of discontinued operations
$
15

 
$
165

Liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
$
1

 
$
5

Asset retirement obligations(b)
32

 
40

Total liabilities of discontinued operations
$
33

 
$
45


(a)
Includes income tax assets related to the abandoned Meredosia and Hutsonville energy centers.
(b)
Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $32 million and $31 million at September 30, 2014, and December 31, 2013, respectively.
The following table presents the components of discontinued operations in Ameren's consolidated statement of income for the three and nine months ended September 30, 2014, and 2013:
 
Three Months
 
Nine Months
 
 
2014
 
2013
 
2014
 
2013
 
Operating revenues
$
—

 
$
311

 
$
1

 
$
878

 
Operating expenses
(1
)
 
(309
)
 
(4
)
 
(1,034
)
(a) 
Operating income (loss)
(1
)
 
2

 
(3
)
 
(156
)
 
Other income (loss)
—

 
—

 
—

 
(1
)
 
Interest charges
—

 
(9
)
 
—

 
(31
)
 
Loss before income taxes
(1
)
 
(7
)
 
(3
)
 
(188
)
 
Income tax (expense) benefit
—

 
4

 
—

 
(24
)
 
Loss from discontinued operations, net of taxes
$
(1
)
 
$
(3
)
 
$
(3
)
 
$
(212
)
 

(a)
Included a noncash pretax asset impairment charge of $175 million for the nine months ended September 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell.
Segment Information (Tables)
Schedule Of Segment Reporting Information By Segment
The following table presents information about the reported revenues and specified items reflected in Ameren’s net income attributable to Ameren Corporation from continuing operations for the three and nine months ended September 30, 2014, and 2013, and total assets of continuing operations as of September 30, 2014, and December 31, 2013.
Three Months
Ameren
Missouri
 
Ameren
Illinois
 
Other
 
Intersegment
Eliminations
 
Ameren
 
2014
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,089

 
$
572

 
$
9

  
$
—

 
$
1,670

 
Intersegment revenues
8

 
—

 
2

  
(10
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
222

 
75

 
(3
)
 
—

 
294

 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
1,088

 
$
547

 
$
3

 
$
—

 
$
1,638

 
Intersegment revenues
5

 
—

 
1

 
(6
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
238

 
77

 
(10
)
 
—

 
305

 
Nine Months
  
 
  
 
  
 
  
 
  
 
2014
 
 
 
 
 
 
 
 
 
 
External revenues
$
2,793

 
$
1,864

 
$
26

 
$
—

 
$
4,683

 
Intersegment revenues
21

 
1

 
3

 
(25
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
395

 
156

 
(10
)
 
—

 
541

 
2013
 
 
 
 
 
 
 
 
 
 
External revenues
$
2,760

 
$
1,744

 
$
12

 
$
—

 
$
4,516

 
Intersegment revenues
18

 
3

 
2

 
(23
)
 
—

 
Net income (loss) attributable to Ameren Corporation from continuing operations
362

 
139

 
(37
)
 
—

 
464

 
As of September 30, 2014:
 
 
 
 
 
 
 
 
 
 
Total assets
$
13,179

 
$
7,983

 
$
810

 
$
(111
)
 
$
21,861

(a) 
As of December 31, 2013:
 
 
 
 
 
 
 
 
 
 
Total assets
$
12,904

 
$
7,454

 
$
752

 
$
(233
)
 
$
20,877

(a) 
(a)    Excludes total assets from discontinued operations of $15 million and $165 million as of September 30, 2014, and December 31, 2013, respectively.
Summary Of Significant Accounting Policies (Narrative) (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended 9 Months Ended 1 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Sep. 30, 2014
Union Electric Company
Dec. 31, 2013
Union Electric Company
Dec. 31, 2013
Electric Energy, Inc
Apr. 30, 2014
Performance Shares
Sep. 30, 2014
Performance Shares
Dec. 31, 2013
Power
Union Electric Company
customer
Dec. 31, 2013
Power
Ameren Illinois Company
customer
Dec. 31, 2013
Natural Gas
Union Electric Company
customer
Dec. 31, 2013
Natural Gas
Ameren Illinois Company
customer
Basis Of Presentation And Significant Accounting Policies [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount
0 
0 
0 
0 
 
 
 
 
 
 
 
 
 
 
Asset Retirement Obligation, Liabilities Incurred
 
 
$ 2 
 
 
$ 2 
 
 
 
 
 
 
 
 
Number of customers
 
 
 
 
 
 
 
 
 
 
1,200,000 
1,200,000 
127,000 
807,000 
Maximum shares available for grants
8 
 
8 
 
 
 
 
 
 
 
 
 
 
 
Fair value of each share unit, per share
 
 
 
 
 
 
 
 
$ 50.34 1
$ 38.90 2
 
 
 
 
Closing common share price
 
 
 
 
$ 36.16 
 
 
 
 
 
 
 
 
 
Performance period
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
Risk free interest rate period
 
 
 
 
 
 
 
 
 
3 years 
 
 
 
 
Three-year risk-free rate
 
 
 
 
 
 
 
 
 
0.78% 
 
 
 
 
Volatility rate, minimum
 
 
 
 
 
 
 
 
12.00% 
12.00% 
 
 
 
 
Volatility rate, maximum
 
 
 
 
 
 
 
 
18.00% 
18.00% 
 
 
 
 
Book value of renewable energy credits
$ 20 
 
$ 20 
 
$ 22 
$ 20 
$ 22 
 
 
 
 
 
 
 
Percentage of EEI not owned by Ameren
 
 
 
 
 
 
 
20.00% 
 
 
 
 
 
 
Summary Of Significant Accounting Policies Schedule of Earnings Per Share Basic And Diluted (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Schedule of Earnings Per Share Basic And Diluted [Abstract]
 
 
 
 
Continuing Operations
$ 294 
$ 305 
$ 541 
$ 464 
Discontinued Operations
(1)
(3)
(3)
(212)
Net Income (Loss) Attributable to Parent
$ 293 
$ 302 
$ 538 
$ 252 
Average Common Shares Outstanding - Basic
242.6 
242.6 
242.6 
242.6 
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements
1.7 
2.5 
1.7 
1.8 
Average Common Shares Outstanding - Diluted
244.3 
245.1 
244.3 
244.4 
Continuing Operations
$ 1.21 
$ 1.26 
$ 2.23 
$ 1.92 
Discontinued Operations
   
$ (0.01)
$ (0.01)
$ (0.88)
Earnings Per Share, Basic
$ 1.21 
$ 1.25 
$ 2.22 
$ 1.04 
Continuing Operations
$ 1.20 
$ 1.25 
$ 2.21 
$ 1.91 
Discontinued Operations
   
$ (0.01)
$ (0.01)
$ (0.88)
Earnings Per Share, Diluted
$ 1.20 
$ 1.24 
$ 2.20 
$ 1.03 
Summary Of Significant Accounting Policies (Schedule Of Amortization Expense Based On Usage Of Renewable Energy Credits And Emission Allowances) (Detail) (REC and Emission Allowances, USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Amortization of intangible assets
$ 2 
$ 2 
$ 14 
$ 9 
Union Electric Company
 
 
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Amortization of intangible assets
1 
   
7 
1 1
Ameren Illinois Company
 
 
 
 
Finite-Lived Intangible Assets [Line Items]
 
 
 
 
Amortization of intangible assets
$ 1 
$ 2 
$ 7 
$ 9 
Summary Of Significant Accounting Policies (Schedule Of Excise Taxes) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Accounting Policies [Line Items]
 
 
 
 
Excise tax expense
$ 56 
$ 59 
$ 166 
$ 163 
Union Electric Company
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
Excise tax expense
47 
49 
120 
120 
Ameren Illinois Company
 
 
 
 
Accounting Policies [Line Items]
 
 
 
 
Excise tax expense
$ 9 
$ 10 
$ 46 
$ 43 
Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Schedule of Unrecognized Tax Benefits (Detriments)) (Details) (USD $)
In Millions, unless otherwise specified
1 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2014
Union Electric Company
Dec. 31, 2013
Union Electric Company
Sep. 30, 2014
Ameren Illinois Company
Dec. 31, 2013
Ameren Illinois Company
Oct. 31, 2014
Subsequent Event [Member]
Oct. 31, 2014
Subsequent Event [Member]
Union Electric Company
Sep. 30, 2014
Tax Year 2013 [Member]
Sep. 30, 2014
Tax Year 2013 [Member]
Union Electric Company
Sep. 30, 2014
Tax Year 2013 [Member]
Ameren Illinois Company
Sep. 30, 2014
2011 and 2012 Tax Years [Member]
Sep. 30, 2014
New Ameren Energy Resources Company, LLC
Tax Year 2013 [Member]
Schedule of Unrecognized Tax Benefits (Detriments) [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefit recorded in Accumulated deferred income taxes, net
$ 89 
$ 84 
$ 13 
$ 15 
$ 2 
    
 
 
 
 
 
 
 
Unrecognized tax benefits (detriments)
97 
90 
35 
31 
1 
(1)
 
 
 
 
 
 
 
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities
 
 
 
 
 
 
16 
9 
 
 
 
 
 
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit
$ 18 
 
 
 
 
 
 
 
$ 73 
$ 17 
$ 1 
$ 6 
$ 55 
Summary Of Significant Accounting Policies Summary of Significant Accounting Policies (Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact the Effective Tax Rate) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact Effective Tax Rate [Line Items]
 
 
Unrecognized tax benefits (detriments) that would impact effective tax rate
$ 55 
$ 54 
Union Electric Company
 
 
Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact Effective Tax Rate [Line Items]
 
 
Unrecognized tax benefits (detriments) that would impact effective tax rate
3 
3 
Ameren Illinois Company
 
 
Schedule of Unrecognized Tax Benefits (Detriments) That Would Impact Effective Tax Rate [Line Items]
 
 
Unrecognized tax benefits (detriments) that would impact effective tax rate
   
   
Summary Of Significant Accounting Policies (Equity Changes Attributable To Noncontrolling Interest) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Electric Energy, Inc
Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward]
 
 
 
 
 
Noncontrolling interest, beginning of period
$ 142 1
$ 151 1
$ 142 
$ 151 1
 
Net income from continuing operations attributable to noncontrolling interests
2 
2 
5 
5 
 
Dividends paid to noncontrolling interest holders
(2)
(2)
(5)
(5)
 
Noncontrolling interest, end of period
$ 142 1
$ 151 1
$ 142 1
$ 151 1
 
Percentage of EEI not owned by Ameren
 
 
 
 
20.00% 
Rate And Regulatory Matters (Narrative-Missouri) (Detail) (USD $)
1 Months Ended 9 Months Ended 1 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2014
Union Electric Company
Dec. 31, 2013
Union Electric Company
Sep. 30, 2014
Ameren Illinois Company
Dec. 31, 2013
Ameren Illinois Company
Jul. 31, 2014
Electric Distribution [Member]
Union Electric Company
Pending Rate Case [Member]
Sep. 30, 2014
Electric Distribution [Member]
Union Electric Company
Pending Rate Case [Member]
Sep. 30, 2014
Electric Distribution [Member]
Union Electric Company
Accounting Authority Order Request [Member]
Feb. 28, 2014
Customer [Domain]
Electric Distribution [Member]
Union Electric Company
Feb. 13, 2014
Customer [Domain]
Electric Distribution [Member]
Union Electric Company
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Public Utilities, Requested Rate Increase (Decrease), Amount
 
 
 
 
 
 
$ 264,000,000 
 
 
 
 
Plant Additions to Rate Base
 
 
 
 
 
 
1,400,000,000 
 
 
 
 
Requested Rate Increase Related to Net Energy Costs
 
 
 
 
 
 
127,000,000 
 
 
 
 
Sharing Level For Fac
 
 
 
 
 
 
95.00% 
 
 
 
 
Public Utilities, Requested Return on Equity, Percentage
 
 
 
 
 
 
10.40% 
 
 
 
 
Public Utilities, Requested Equity Capital Structure, Percentage
 
 
 
 
 
 
51.60% 
 
 
 
 
Rate Base
 
 
 
 
 
 
7,300,000,000 
 
 
 
 
Number of Months to complete MoPSC Electric Service Proceeding
 
 
 
 
 
 
11 months 
 
 
 
 
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration
 
 
 
 
 
 
 
15 years 
 
 
 
Regulatory assets
$ 1,259,000,000 
$ 1,240,000,000 
$ 539,000,000 
$ 534,000,000 
$ 712,000,000 
$ 701,000,000 
 
 
$ 36,000,000 
 
 
Number of Customers Filed Complaint Case
 
 
 
 
 
 
 
 
 
 
37 
Contested return on equity
 
 
 
 
 
 
 
 
 
9.80% 
 
Rate And Regulatory Matters (Narrative-Illinois) (Detail) (USD $)
12 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended 9 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2014
Ameren Illinois Company
Dec. 31, 2013
Ameren Illinois Company
Dec. 31, 2013
Ameren Illinois Company
Gas Distribution [Member]
Final Rate Order [Member]
Dec. 31, 2013
Ameren Illinois Company
Gas Distribution [Member]
Rate order appeal [Member]
Sep. 30, 2014
Ieima [Member]
Ameren Illinois Company
Electric Distribution [Member]
IEMA Revenue Requirement Reconciliation [Member]
Sep. 30, 2014
Ieima [Member]
Ameren Illinois Company
Electric Distribution [Member]
2013 IEMA Revenue Requirement Reconciliation [Member]
Sep. 30, 2014
Ieima [Member]
Ameren Illinois Company
Electric Distribution [Member]
2012 IEMA Revenue Requirement Reconciliation [Member]
Sep. 30, 2014
Icc Staff Recommendation [Member]
Ieima [Member]
Ameren Illinois Company
Electric Distribution [Member]
IEMA Revenue Requirement Reconciliation [Member]
Sep. 30, 2014
Other Intervenors [Member]
Ieima [Member]
Ameren Illinois Company
Electric Distribution [Member]
IEMA Revenue Requirement Reconciliation [Member]
Sep. 30, 2014
Administrative Law Judge [Member]
Ieima [Member]
Ameren Illinois Company
Electric Distribution [Member]
IEMA Revenue Requirement Reconciliation [Member]
Sep. 30, 2014
Minimum
Ameren Illinois Company
Pending Ferc Case [Member]
Sep. 30, 2014
Maximum
Ameren Illinois Company
Pending Ferc Case [Member]
Sep. 30, 2014
Pending Ferc Case [Member]
Midwest Independent Transmission System Operator, Inc [Member]
Sep. 30, 2014
Pending Ferc Case [Member]
Midwest Independent Transmission System Operator, Inc [Member]
Ameren Illinois Company
Sep. 30, 2014
Pending Ferc Case [Member]
Minimum
Midwest Independent Transmission System Operator, Inc [Member]
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets
$ 1,259,000,000 
$ 1,240,000,000 
$ 712,000,000 
$ 701,000,000 
 
 
$ 76,000,000 
$ 64,000,000 
 
 
 
 
 
 
 
 
 
Current regulatory liabilities
132,000,000 
216,000,000 
121,000,000 
159,000,000 
 
 
 
 
13,000,000 
 
 
 
 
 
 
 
 
Public Utilities, Requested Rate Increase (Decrease), Amount
 
 
 
 
 
 
205,000,000 
 
 
205,000,000 
7,000,000 
204,000,000 
 
 
 
 
 
Authorized Increase in Revenue from Utility Service
 
 
 
 
32,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Public Utilities, Approved Return on Equity, Percentage
 
 
 
 
9.10% 
10.40% 
 
 
 
 
 
 
 
 
12.38% 
 
10.57% 
Percent Of Capital Structure Composed Of Equity
 
 
 
 
51.70% 
 
 
 
 
 
 
 
 
 
 
 
 
Rate Base
 
 
 
 
1,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Loss Contingency, Estimate of Possible Loss
 
 
 
 
 
 
 
 
 
 
 
 
$ 4,000,000 
$ 19,000,000 
$ 14,000,000 
$ 11,000,000 
 
Rate And Regulatory Matters (Narrative-Federal) (Detail) (USD $)
In Millions, unless otherwise specified
12 Months Ended 9 Months Ended 9 Months Ended 1 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2014
Ameren Illinois Company
Dec. 31, 2013
Ameren Illinois Company
Sep. 30, 2014
Ameren Illinois Company
Pending Ferc Case [Member]
Minimum
Sep. 30, 2014
Ameren Illinois Company
Pending Ferc Case [Member]
Maximum
Sep. 30, 2014
Union Electric Company
Dec. 31, 2013
Union Electric Company
Dec. 31, 2013
Union Electric Company
New Nuclear Energy Center COL [Member]
Dec. 31, 2013
Union Electric Company
New Nuclear Energy Center COL [Member]
Minimum
Dec. 31, 2013
Union Electric Company
New Nuclear Energy Center COL [Member]
Maximum
Sep. 30, 2014
Wholesale Distribution Rate Case [Member]
Dec. 31, 2013
Wholesale Distribution Rate Case [Member]
Sep. 30, 2014
Wholesale Distribution Rate Case [Member]
Ameren Illinois Company
Dec. 31, 2013
Wholesale Distribution Rate Case [Member]
Ameren Illinois Company
Dec. 31, 2012
Entergy Refund [Member]
Union Electric Company
Sep. 30, 2014
Entergy Refund [Member]
Union Electric Company
Sep. 30, 2014
Midwest Independent Transmission System Operator, Inc [Member]
Pending Ferc Case [Member]
Sep. 30, 2014
Midwest Independent Transmission System Operator, Inc [Member]
Pending Ferc Case [Member]
Minimum
Sep. 30, 2014
Midwest Independent Transmission System Operator, Inc [Member]
Pending Ferc Case [Member]
Ameren Illinois Company
Sep. 30, 2014
New England Transmission Owners [Member]
Pending Ferc Case [Member]
Sep. 30, 2014
New England Transmission Owners [Member]
Pending Ferc Case [Member]
Minimum
Sep. 30, 2014
New England Transmission Owners [Member]
Pending Ferc Case [Member]
Maximum
Sep. 30, 2014
Estimated Annual Reduction to Revenues From MISO ROE [Member]
Midwest Independent Transmission System Operator, Inc [Member]
Pending Ferc Case [Member]
Sep. 30, 2014
Estimated Annual Reduction to Revenues From MISO ROE [Member]
Midwest Independent Transmission System Operator, Inc [Member]
Pending Ferc Case [Member]
Ameren Illinois Company
Nov. 30, 2014
Subsequent Event [Member]
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current regulatory liabilities
$ 132 
$ 216 
$ 121 
$ 159 
 
 
$ 11 
$ 57 
 
 
 
$ 24 
$ 13 
$ 24 
$ 13 
 
 
 
 
 
 
 
 
 
 
 
Loss Contingency, Estimate of Possible Loss
 
 
 
 
4 
19 
 
 
 
 
 
 
 
 
 
 
25 
14 
 
11 
 
 
 
16 
12 
 
Customer Requested Rate on Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9.15% 
 
 
 
 
 
 
 
 
Public Utilities, Approved Return on Equity, Percentage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
12.38% 
10.57% 
 
11.14% 
10.57% 
11.74% 
 
 
 
Incentive adder to FERC allowed base return on common equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50 
Proceeds from Legal Settlements
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31 
 
 
 
 
 
 
 
 
 
 
Investments in Power and Distribution Projects
 
 
 
 
 
 
 
 
$ 69 
$ 80 
$ 120 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-Term Debt And Liquidity (Narrative) (Detail) (USD $)
In Billions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Utilities [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Short Term Debt, Weighted Average Interest Rate During Period
0.10% 
0.05% 
0.23% 
0.08% 
Credit Agreements 2012 [Member]
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Line of credit facility, maximum borrowing capacity
$ 1.30 
 
$ 1.30 
 
Actual debt-to-capital ratio
0.49 
 
0.49 
 
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
2.0 to 1.0 
 
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
6.1 to 1.0 
 
Credit Agreements 2012 [Member] |
Maximum
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Actual debt-to-capital ratio
0.65 
 
0.65 
 
Missouri Credit Agreement 2012 [Member] |
Union Electric Company
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Actual debt-to-capital ratio
0.48 
 
0.48 
 
Illinois Credit Agreement 2012 [Member] |
Ameren Illinois Company
 
 
 
 
Line of Credit Facility [Line Items]
 
 
 
 
Actual debt-to-capital ratio
0.46 
 
0.46 
 
Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Commercial Paper outstanding) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Line of Credit Facility [Line Items]
 
 
Commercial paper outstanding
$ 753 
$ 368 
Ameren (parent)
 
 
Line of Credit Facility [Line Items]
 
 
Commercial paper outstanding
499 
368 
Union Electric Company
 
 
Line of Credit Facility [Line Items]
 
 
Commercial paper outstanding
65 
   
Ameren Illinois Company
 
 
Line of Credit Facility [Line Items]
 
 
Commercial paper outstanding
$ 189 
    
Short-Term Debt And Liquidity Short-Term Debt and Liquidity (Commercial Paper) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Line of Credit Facility [Line Items]
 
 
Average Daily Commercial Paper Borrowings Outstanding
$ 609 
$ 26 
Weighted Average Interest Rate
0.35% 
0.52% 
Peak Short Term Borrowings
907 1
92 1
Peak Short Term Borrowings Interest Rate
0.75% 
0.85% 
Ameren (parent)
 
 
Line of Credit Facility [Line Items]
 
 
Average Daily Commercial Paper Borrowings Outstanding
386 
26 
Weighted Average Interest Rate
0.36% 
0.52% 
Peak Short Term Borrowings
531 1
92 1
Peak Short Term Borrowings Interest Rate
0.75% 
0.85% 
Union Electric Company
 
 
Line of Credit Facility [Line Items]
 
 
Average Daily Commercial Paper Borrowings Outstanding
141 
   
Weighted Average Interest Rate
0.38% 
   
Peak Short Term Borrowings
495 1
   1
Peak Short Term Borrowings Interest Rate
0.70% 
   
Ameren Illinois Company
 
 
Line of Credit Facility [Line Items]
 
 
Average Daily Commercial Paper Borrowings Outstanding
157 
   
Weighted Average Interest Rate
0.31% 
   
Peak Short Term Borrowings
$ 300 1
    1
Peak Short Term Borrowings Interest Rate
0.34% 
   
Long-Term Debt And Equity Financings (Narrative) (Detail) (USD $)
9 Months Ended 1 Months Ended 1 Months Ended 1 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Union Electric Company
Sep. 30, 2013
Union Electric Company
Sep. 30, 2014
Ameren Missouri And Ameren Illinois [Member]
Sep. 30, 2014
Ameren Illinois Company
Sep. 30, 2013
Ameren Illinois Company
Sep. 30, 2014
Ameren Illinois Company
Federal Energy Regulatory Commission Restriction [Member]
Sep. 30, 2014
Ameren Illinois Company
Minimum
Federal Energy Regulatory Commission Restriction [Member]
May 31, 2014
Senior Unsecured Notes8875 Due2014 [Member]
Parent Company [Member]
May 15, 2014
Senior Unsecured Notes8875 Due2014 [Member]
Parent Company [Member]
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Ameren Illinois Company
Apr. 30, 2014
Secured Debt [Member]
Senior Secured Notes, 3.50%, Due 2024 [Member]
Union Electric Company
May 31, 2014
Secured Debt [Member]
Senior Secured Notes550 Due2014 [Member]
Union Electric Company
May 15, 2014
Secured Debt [Member]
Senior Secured Notes550 Due2014 [Member]
Union Electric Company
Jun. 30, 2014
Secured Debt [Member]
Senior Secured Notes, 4.30%, Due 2044 [Member] [Member]
Ameren Illinois Company
Long-Term Debt And Equity Financings [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Repayments of Other Long-term Debt
$ 692,000,000 
    
 
 
 
 
 
 
 
$ 425,000,000 
 
 
 
 
 
 
Debt Instrument, Face Amount
 
 
 
 
 
1,000,000 
 
 
 
 
 
 
350,000,000 
 
 
250,000,000 
Redemptions of Long-term Debt
 
 
104,000,000 
   
 
163,000,000 
   
 
 
 
 
163,000,000 
 
104,000,000 
 
 
Debt Instrument, Interest Rate, Stated Percentage
 
 
 
 
 
 
 
 
 
 
8.875% 
 
3.50% 
 
5.50% 
4.30% 
Assumed interest rate
 
 
 
 
5.00% 
 
 
 
 
 
 
 
 
 
 
 
Dividend rate
 
 
 
 
6.00% 
 
 
 
 
 
 
 
 
 
 
 
Common stock equity to total capitalization
 
 
 
 
 
 
 
54.00% 
30.00% 
 
 
 
 
 
 
 
Proceeds from Issuance of Secured Debt
 
 
 
 
 
 
 
 
 
 
 
 
$ 348,000,000 
 
 
$ 246,000,000 
Long-Term Debt And Equity Financings Long-Term Debt and Equity Financings (Schedule of Debt Redemptions (Details) (Ameren Illinois Company, USD $)
9 Months Ended 1 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Series1993590 Due2023 [Member]
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Series1994A 570 Due 2024 [Member]
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Series C11993595 Due2026 [Member]
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Series C21993570 Due2026 [Member]
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Series1998A 5 Point 40 Due 2028 [Member]
Jan. 31, 2014
Environmental Improvement And Pollution Control Revenue Bonds [Member]
Series1998b540 Due2028 [Member]
Long-Term Debt And Equity Financings [Line Items]
 
 
 
 
 
 
 
 
 
Debt Instrument, Face Amount
$ 1,000,000 
 
 
 
 
 
 
 
 
Redemptions of Long-term Debt
$ 163,000,000 
    
$ 163,000,000 
$ 32,000,000 1
$ 36,000,000 1
$ 35,000,000 
$ 8,000,000 
$ 19,000,000 
$ 33,000,000 
Long-Term Debt And Equity Financings (Schedule Of Covered Ratio) (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Union Electric Company
 
Long-Term Debt And Equity Financings [Line Items]
 
Bonds Issuable
$ 3,304 1
Preferred Stock Issuable
2,823 
Retired bond capacity
833 
Union Electric Company |
Actual Ratio [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Restricted payment interest coverage ratio, Actual
4.6 
Dividend Coverage Ratio
126.3 
Ameren Illinois Company
 
Long-Term Debt And Equity Financings [Line Items]
 
Bonds Issuable
3,636 1 2
Preferred Stock Issuable
203 3
Retired bond capacity
$ 204 
Ameren Illinois Company |
Actual Ratio [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Restricted payment interest coverage ratio, Actual
6.7 
Dividend Coverage Ratio
2.4 
Minimum |
Union Electric Company |
Minimum Required Ratio [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Restricted payment interest coverage ratio, Actual
2.0 4
Dividend Coverage Ratio
2.5 5
Minimum |
Ameren Illinois Company |
Minimum Required Ratio [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Restricted payment interest coverage ratio, Actual
2.0 4
Dividend Coverage Ratio
1.5 5
Other Income and Expenses (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Other Nonoperating Income (Expense) [Line Items]
 
 
 
 
Allowance for equity funds used during construction
$ 10 1
$ 10 1
$ 26 1
$ 26 1
Interest income on industrial development revenue bonds
6 1
7 1
20 1
21 1
Interest and dividend income
3 1
2 1
8 1
3 1
Other
2 1
1 1
6 1
1 1
Total miscellaneous income
21 1
20 1
60 1
51 1
Donations
3 1
2 1
9 1
7 1
Other
4 1
3 1
11 1
11 1
Total miscellaneous expense
7 1
5 1
20 1
18 1
Union Electric Company
 
 
 
 
Other Nonoperating Income (Expense) [Line Items]
 
 
 
 
Allowance for equity funds used during construction
9 
8 
24 
22 
Interest income on industrial development revenue bonds
6 
7 
20 
21 
Interest and dividend income
   
1 
1 
1 
Total miscellaneous income
15 
16 
45 
44 
Donations
2 
   
5 
3 
Other
2 
2 
5 
7 
Total miscellaneous expense
4 
2 
10 
10 
Ameren Illinois Company
 
 
 
 
Other Nonoperating Income (Expense) [Line Items]
 
 
 
 
Allowance for equity funds used during construction
1 
2 
2 
4 
Interest and dividend income
2 
1 
5 
2 
Other
1 
1 
5 
1 
Total miscellaneous income
4 
4 
12 
7 
Donations
   
   
3 
3 
Other
2 
3 
4 
4 
Total miscellaneous expense
$ 2 
$ 3 
$ 7 
$ 7 
Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Detail)
Sep. 30, 2014
gal
Dec. 31, 2013
gal
Fuel Oils
 
 
Derivative [Line Items]
 
 
Quantity
52,000,000 1
66,000,000 1
Natural Gas
 
 
Derivative [Line Items]
 
 
Quantity
125,000,000 
136,000,000 
Power
 
 
Derivative [Line Items]
 
 
Quantity
12,000,000 
14,000,000 
Uranium
 
 
Derivative [Line Items]
 
 
Quantity
557,000 
796,000 
Union Electric Company |
Fuel Oils
 
 
Derivative [Line Items]
 
 
Quantity
52,000,000 1
66,000,000 1
Union Electric Company |
Natural Gas
 
 
Derivative [Line Items]
 
 
Quantity
23,000,000 
28,000,000 
Union Electric Company |
Power
 
 
Derivative [Line Items]
 
 
Quantity
1,000,000 
3,000,000 
Union Electric Company |
Uranium
 
 
Derivative [Line Items]
 
 
Quantity
557,000 
796,000 
Ameren Illinois Company |
Natural Gas
 
 
Derivative [Line Items]
 
 
Quantity
102,000,000 
108,000,000 
Ameren Illinois Company |
Power
 
 
Derivative [Line Items]
 
 
Quantity
11,000,000 
11,000,000 
Derivative Financial Instruments (Derivative Instruments Carrying Value) (Detail) (Not Designated As Hedging Instrument [Member], USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Derivative [Line Items]
 
 
Derivative assets
$ 16 
$ 34 
Derivative liabilities
167 
178 
Fuel Oils |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
3 
6 
Fuel Oils |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
 
3 
Fuel Oils |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
5 
2 
Fuel Oils |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
1 
1 
Natural Gas |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 
2 
Natural Gas |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 
 
Natural Gas |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
19 
32 
Natural Gas |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
9 
25 
Power |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
10 
23 
Power |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 
 
Power |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
14 
13 
Power |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
116 
99 
Uranium |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 
5 
Uranium |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
1 
1 
Union Electric Company
 
 
Derivative [Line Items]
 
 
Derivative assets
14 
33 
Derivative liabilities
21 
24 
Union Electric Company |
Fuel Oils |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
3 
6 
Union Electric Company |
Fuel Oils |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
 
3 
Union Electric Company |
Fuel Oils |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
5 
2 
Union Electric Company |
Fuel Oils |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
1 
1 
Union Electric Company |
Natural Gas |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
 
1 
Union Electric Company |
Natural Gas |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
3 
5 
Union Electric Company |
Natural Gas |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
3 
6 
Union Electric Company |
Power |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
10 
23 
Union Electric Company |
Power |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 
 
Union Electric Company |
Power |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
6 
4 
Union Electric Company |
Uranium |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
2 
5 
Union Electric Company |
Uranium |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
1 
1 
Ameren Illinois Company
 
 
Derivative [Line Items]
 
 
Derivative assets
2 
1 
Derivative liabilities
146 
154 
Ameren Illinois Company |
Natural Gas |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 
1 
Ameren Illinois Company |
Natural Gas |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets
1 
 
Ameren Illinois Company |
Natural Gas |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
16 
27 
Ameren Illinois Company |
Natural Gas |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
6 
19 
Ameren Illinois Company |
Power |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
8 
9 
Ameren Illinois Company |
Power |
Other Deferred Credits And Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities
$ 116 
$ 99 
Derivative Financial Instruments (Cumulative Amount Of Pretax Net Gains (Losses) On All Derivative Instruments In OCI) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
$ 132 
$ 216 
Current losses deferred as regulatory assets
199 
156 
Fuel Oils
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
4 
 
Fuel Oils |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(5)1
2 
Natural Gas
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
1 
 
Current losses deferred as regulatory assets
19 
 
Natural Gas |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(26)2
(55)
Power
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
10 
 
Current losses deferred as regulatory assets
14 
 
Power |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(119)3
(89)
Uranium
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
2 
 
Uranium |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(3)4
(6)
Union Electric Company
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
11 
57 
Current losses deferred as regulatory assets
137 
118 
Union Electric Company |
Fuel Oils
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
4 
 
Union Electric Company |
Fuel Oils |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(5)1
2 
Union Electric Company |
Natural Gas
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
3 
 
Union Electric Company |
Natural Gas |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(6)2
(10)
Union Electric Company |
Power
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
10 
 
Current losses deferred as regulatory assets
6 
 
Union Electric Company |
Power |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
5 3
19 
Union Electric Company |
Uranium
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
2 
 
Union Electric Company |
Uranium |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(3)4
(6)
Ameren Illinois Company
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
121 
159 
Current losses deferred as regulatory assets
62 
38 
Ameren Illinois Company |
Natural Gas
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
1 
 
Current losses deferred as regulatory assets
16 
 
Ameren Illinois Company |
Natural Gas |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(20)2
(45)
Ameren Illinois Company |
Power
 
 
Derivative [Line Items]
 
 
Current losses deferred as regulatory assets
8 
 
Ameren Illinois Company |
Power |
Regulatory Liabilities Or Assets [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
$ (124)3
$ (108)
Derivative Financial Instruments (Offsetting Derivative Assets and Liabilities) (Details) (Commodity Contract, USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Offsetting Assets and Liabilities [Line Items]
 
 
Gross Amounts Recognized in the Balance Sheet
$ 16 1
$ 34 1
Derivative Instruments
8 
10 
Net Amount
8 
24 
Gross Amounts Recognized in the Balance Sheet
167 1
178 1
Derivative Instruments
8 
10 
Cash Collateral Received/Posted
5 2
24 2
Net Amount
154 
144 
Union Electric Company
 
 
Offsetting Assets and Liabilities [Line Items]
 
 
Gross Amounts Recognized in the Balance Sheet
14 1
33 1
Derivative Instruments
7 
9 
Net Amount
7 
24 
Gross Amounts Recognized in the Balance Sheet
21 1
24 1
Derivative Instruments
7 
9 
Cash Collateral Received/Posted
5 2
9 2
Net Amount
9 
6 
Ameren Illinois Company
 
 
Offsetting Assets and Liabilities [Line Items]
 
 
Gross Amounts Recognized in the Balance Sheet
2 
1 
Derivative Instruments
1 
1 
Net Amount
1 
0 
Gross Amounts Recognized in the Balance Sheet
146 1
154 1
Derivative Instruments
1 
1 
Cash Collateral Received/Posted
 
15 2
Net Amount
$ 145 
$ 138 
Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended 9 Months Ended 12 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2014
Union Electric Company
Dec. 31, 2013
Union Electric Company
Sep. 30, 2014
Ameren Illinois Company
Dec. 31, 2012
Ameren Illinois Company
Derivative [Line Items]
 
 
 
 
 
 
Maximum exposure to counterparties related to derivative contracts
$ 6 
$ 13 
$ 4 
$ 12 
$ 2 
$ 1 
Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 4 
$ 6 
Ameren Illinois Company
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
1 
 
Union Electric Company
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 3 
$ 6 
Fair Value Measurements (Schedule Of Valuation Process And Unobservable Inputs) (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2014
Dec. 31, 2013
Natural Gas |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.30% 1 2
 
Nodal basis
(0.1)1
 
Credit risk
0.43% 1 2
 
Natural Gas |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
2.00% 1 2
 
Nodal basis
0 1
 
Credit risk
0.43% 1 2
 
Natural Gas |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.62% 1 2
 
Nodal basis
(0.1)1
 
Credit risk
0.43% 1 2
 
Natural Gas |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
$ 1 3
 
Natural Gas |
Ameren Illinois Company |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.30% 1 2
 
Nodal basis
(0.1)1
 
Credit risk
0.43% 1 2
 
Natural Gas |
Ameren Illinois Company |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
2.00% 1 2
 
Nodal basis
0 1
 
Credit risk
0.43% 1 2
 
Natural Gas |
Ameren Illinois Company |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.62% 1 2
 
Nodal basis
(0.1)1
 
Credit risk
0.43% 1 2
 
Natural Gas |
Ameren Illinois Company |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
1 3
 
Fuel Oils |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.25% 1 2
0.26% 1 2
Credit risk
0.43% 1 2
 
Fuel Oils |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
1.00% 1 2
2.00% 1 2
Credit risk
0.43% 1 2
 
Fuel Oils |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.72% 1 2
1.00% 1 2
Credit risk
0.43% 1 2
 
Fuel Oils |
Option Model |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
2.00% 4
10.00% 4
Fuel Oils |
Option Model |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
27.00% 4
35.00% 4
Fuel Oils |
Option Model |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
14.00% 4
16.00% 4
Fuel Oils |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
3 3
8 3
Fuel Oils |
Union Electric Company |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.25% 1 2
0.26% 1 2
Credit risk
0.43% 1 2
 
Fuel Oils |
Union Electric Company |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
1.00% 1 2
2.00% 1 2
Credit risk
0.43% 1 2
 
Fuel Oils |
Union Electric Company |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.72% 1 2
1.00% 1 2
Credit risk
0.43% 1 2
 
Fuel Oils |
Union Electric Company |
Option Model |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
2.00% 4
10.00% 4
Fuel Oils |
Union Electric Company |
Option Model |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
27.00% 4
35.00% 4
Fuel Oils |
Union Electric Company |
Option Model |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Volatilities
14.00% 4
16.00% 4
Fuel Oils |
Union Electric Company |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
3 3
8 3
Fuel Oils |
Derivative Liabilities
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(3)3
(3)3
Fuel Oils |
Derivative Liabilities |
Union Electric Company
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(3)3
(3)3
Power |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.40% 1 2
0.39% 1 2
Nodal basis
(6)1
(3)1
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
29 1
25 1
Estimated auction price
(1,853)4
(1,594)4
Power |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.40% 1 2
0.50% 1 2
Nodal basis
0 1
(1)1
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
59 1
51 1
Estimated auction price
2,087 4
945 4
Power |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.40% 1 2
0.42% 1 2
Nodal basis
(3)1
(2)1
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
35 1
32 1
Estimated auction price
199 4
305 4
Power |
Fundamental Energy Production Model |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
2.00% 4 5
3.00% 4 5
Estimated future gas prices
4 4
4 4
Power |
Fundamental Energy Production Model |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
2.00% 4 5
4.00% 4 5
Estimated future gas prices
5 4
5 4
Power |
Fundamental Energy Production Model |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
2.00% 4 5
4.00% 4 5
Estimated future gas prices
5 4
5 4
Power |
Contract Price Allocation |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
5 4
5 4
Power |
Contract Price Allocation |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
7 4
7 4
Power |
Contract Price Allocation |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
6 4
6 4
Power |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
10 3 6
21 3 7
Power |
Union Electric Company |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.40% 1 2
0.39% 1 2
Nodal basis
 
(3)1
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
30 1
25 1
Estimated auction price
(1,853)4
(1,594)4
Power |
Union Electric Company |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.40% 1 2
0.50% 1 2
Nodal basis
 
(1)1
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
59 1
51 1
Estimated auction price
2,087 4
945 4
Power |
Union Electric Company |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Counterparty credit risk
0.40% 1 2
0.42% 1 2
Nodal basis
 
(2)1
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
48 1
40 1
Estimated auction price
199 4
305 4
Power |
Union Electric Company |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
10 3 6
21 3 7
Power |
Ameren Illinois Company |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Nodal basis
(6)4
(4)4
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
29 4
27 4
Power |
Ameren Illinois Company |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Nodal basis
0 4
0 4
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
42 4
36 4
Power |
Ameren Illinois Company |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Nodal basis
(3)4
(2)4
Credit risk
0.43% 1 2
2.00% 1 2
Average forward peak and off-peak pricing
33 4
30 4
Power |
Ameren Illinois Company |
Fundamental Energy Production Model |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
2.00% 4 5
3.00% 4 5
Estimated future gas prices
4 4
4 4
Power |
Ameren Illinois Company |
Fundamental Energy Production Model |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
2.00% 4 5
4.00% 4 5
Estimated future gas prices
5 4
5 4
Power |
Ameren Illinois Company |
Fundamental Energy Production Model |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Escalation rate
2.00% 4 5
4.00% 4 5
Estimated future gas prices
5 4
5 4
Power |
Ameren Illinois Company |
Contract Price Allocation |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
5 4
5 4
Power |
Ameren Illinois Company |
Contract Price Allocation |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
7 4
7 4
Power |
Ameren Illinois Company |
Contract Price Allocation |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Estimated renewable energy credit costs
6 4
6 4
Power |
Ameren Illinois Company |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
 
   3 7
Power |
Derivative Liabilities
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(129)3 6
(110)3 7
Power |
Derivative Liabilities |
Union Electric Company
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(5)3 6
(2)3 7
Power |
Derivative Liabilities |
Ameren Illinois Company
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(124)3 6
(108)3 7
Uranium |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Average forward pricing
35 4
34 4
Uranium |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Average forward pricing
41 4
41 4
Uranium |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Average forward pricing
36 4
36 4
Uranium |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
   3
   3
Uranium |
Union Electric Company |
Discounted Cash Flow |
Minimum
 
 
Fair Value Inputs [Abstract]
 
 
Average forward pricing
35 4
34 4
Uranium |
Union Electric Company |
Discounted Cash Flow |
Maximum
 
 
Fair Value Inputs [Abstract]
 
 
Average forward pricing
41 4
41 4
Uranium |
Union Electric Company |
Discounted Cash Flow |
Weighted Average
 
 
Fair Value Inputs [Abstract]
 
 
Average forward pricing
36 4
36 4
Uranium |
Union Electric Company |
Derivative Assets
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative assets
   3
   3
Uranium |
Derivative Liabilities
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
(3)3
(6)3
Uranium |
Derivative Liabilities |
Union Electric Company
 
 
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
 
 
Derivative liabilities
$ (3)3
$ (6)3
Fair Value Measurements (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Valuation adjustments related to net derivative contracts, liabilities
$ 1 
$ 3 
Union Electric Company
 
 
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
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Valuation adjustments related to net derivative contracts, liabilities
$ 1 
$ 3 
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
Sep. 30, 2014
Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
$ 527 1
$ 494 
Assets fair value
543 2
528 2
Excluded receivables, payables, and accrued income, net
2 
 
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
527 1
494 
Assets fair value
541 2
527 2
Commodity Contract
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
16 2
34 2
Derivative liabilities
167 2
178 2
Commodity Contract |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
14 2
33 2
Derivative liabilities
21 2
24 2
Commodity Contract |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 
1 
Derivative liabilities
146 2
154 2
Commodity Contract |
Fuel Oils
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 2
9 2
Derivative liabilities
6 2
3 2
Commodity Contract |
Fuel Oils |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 2
9 2
Derivative liabilities
6 2
3 2
Commodity Contract |
Natural Gas
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
2 2
Derivative liabilities
28 2
57 2
Commodity Contract |
Natural Gas |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
 
1 2
Derivative liabilities
6 2
11 2
Commodity Contract |
Natural Gas |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
1 2
Derivative liabilities
22 2
46 2
Commodity Contract |
Power
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
11 2
23 2
Derivative liabilities
130 2
112 2
Commodity Contract |
Power |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
11 2
23 2
Derivative liabilities
6 2
4 2
Commodity Contract |
Power |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
124 2
108 2
Commodity Contract |
Uranium
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
3 2
6 2
Commodity Contract |
Uranium |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
3 2
6 2
Cash and cash equivalents
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 
3 
Cash and cash equivalents |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 
3 
Equity Securities |
U.S. large capitalization
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
348 
332 
Equity Securities |
U.S. large capitalization |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
348 
332 
Debt Securities |
Corporate bonds
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
60 
52 
Debt Securities |
Corporate bonds |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
60 
52 
Debt Securities |
Municipal bonds
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
2 
2 
Debt Securities |
Municipal bonds |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
2 
2 
Debt Securities |
US treasury and government securities
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
100 
94 
Debt Securities |
US treasury and government securities |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
100 
94 
Debt Securities |
Asset-backed Securities
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
11 
10 
Debt Securities |
Asset-backed Securities |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
11 
10 
Debt Securities |
Other Debt Securities
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
5 
1 
Debt Securities |
Other Debt Securities |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
5 
1 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1)
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
349 
335 
Assets fair value
349 2
336 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
349 
335 
Assets fair value
349 2
336 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Commodity Contract
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
1 2
Derivative liabilities
5 2
3 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Commodity Contract |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
1 2
Derivative liabilities
5 2
3 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Commodity Contract |
Fuel Oils
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
1 2
Derivative liabilities
3 2
 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Commodity Contract |
Fuel Oils |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
   2
1 2
Derivative liabilities
3 2
 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Commodity Contract |
Natural Gas
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
2 2
3 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Commodity Contract |
Natural Gas |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
 
   2
Derivative liabilities
2 2
3 2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Commodity Contract |
Natural Gas |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
 
   2
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Cash and cash equivalents
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 
3 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Cash and cash equivalents |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
1 
3 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Equity Securities |
U.S. large capitalization
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
348 
332 
Quoted Prices In Active Markets For Identical Assets or Liabilities (Level 1) |
Equity Securities |
U.S. large capitalization |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
348 
332 
Significant Other Observable Inputs (Level 2)
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
178 
159 
Assets fair value
180 2
163 2
Significant Other Observable Inputs (Level 2) |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
178 
159 
Assets fair value
179 2
162 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
2 2
4 2
Derivative liabilities
27 2
56 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
3 2
Derivative liabilities
5 2
10 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
22 2
46 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract |
Natural Gas
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
2 2
Derivative liabilities
26 2
54 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract |
Natural Gas |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
 
1 2
Derivative liabilities
4 2
8 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract |
Natural Gas |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
1 2
Derivative liabilities
22 2
46 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract |
Power
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
2 2
Derivative liabilities
1 2
2 2
Significant Other Observable Inputs (Level 2) |
Commodity Contract |
Power |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
2 2
Derivative liabilities
1 2
2 2
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Corporate bonds
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
60 
52 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Corporate bonds |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
60 
52 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Municipal bonds
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
2 
2 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Municipal bonds |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
2 
2 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
US treasury and government securities
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
100 
94 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
US treasury and government securities |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
100 
94 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Asset-backed Securities
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
11 
10 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Asset-backed Securities |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
11 
10 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Other Debt Securities
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
5 
1 
Significant Other Observable Inputs (Level 2) |
Debt Securities |
Other Debt Securities |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Nuclear Decommissioning Trust Fund
5 
1 
Significant Other Unobservable Inputs (Level 3)
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Assets fair value
14 2
29 2
Significant Other Unobservable Inputs (Level 3) |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Assets fair value
13 2
29 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
14 2
29 2
Derivative liabilities
135 2
119 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
13 2
29 2
Derivative liabilities
11 2
11 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
124 2
108 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Fuel Oils
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 2
8 2
Derivative liabilities
3 2
3 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Fuel Oils |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
3 2
8 2
Derivative liabilities
3 2
3 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Natural Gas
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
 
Derivative liabilities
   2
 
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Natural Gas |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
1 2
   2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Power
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
10 2
21 2
Derivative liabilities
129 2
110 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Power |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative assets
10 2
21 2
Derivative liabilities
5 2
2 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Power |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
124 2
108 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Uranium
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
3 2
6 2
Significant Other Unobservable Inputs (Level 3) |
Commodity Contract |
Uranium |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Derivative liabilities
$ 3 2
$ 6 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 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Fuel Oils
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
$ 2 
$ 3 
$ 5 
$ 5 
Included in regulatory assets/liabilities
(2)
1 
(3)
(1)
Purchases
 
1 
 
2 
Sales
 
(1)
 
(1)
Settlements
 
(1)
(2)
(2)
Ending balance
0 
3 
0 
3 
Change in unrealized gains (losses) related to assets/liabilities held at period end
(2)
1 
(2)
0 
Uranium
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
(7)
(3)
(6)
(2)
Included in regulatory assets/liabilities
3 
 
(1)
(2)
Purchases
 
(2)
 
(2)
Settlements
1 
 
4 
1 
Ending balance
(3)
(5)
(3)
(5)
Change in unrealized gains (losses) related to assets/liabilities held at period end
3 
(2)
0 
(2)
Natural Gas
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
0 
1 
0 
0 
Included in regulatory assets/liabilities
1 
(2)
1 
(1)
Purchases
 
1 
(1)
1 
Settlements
 
 
1 
 
Ending balance
1 
0 
1 
0 
Change in unrealized gains (losses) related to assets/liabilities held at period end
   
(1)
 
 
Power
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
(88)
(43)
(89)
(100)
Included in regulatory assets/liabilities
(28)
(20)
(42)
1 
Purchases
 
 
34 
40 
Sales
 
1 
 
1 
Settlements
(3)
(3)
(22)
(9)
Transfers into Level 3
 
(1)
 
(3)
Transfer out of Level 3
 
 
 
4 
Ending balance
(119)
(66)
(119)
(66)
Change in unrealized gains (losses) related to assets/liabilities held at period end
(28)
(18)
(24)
(7)
Union Electric Company |
Fuel Oils
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
2 
3 
5 
5 
Included in regulatory assets/liabilities
(2)
1 
(3)
(1)
Purchases
 
1 
 
2 
Sales
 
(1)
 
(1)
Settlements
 
(1)
(2)
(2)
Ending balance
0 
3 
0 
3 
Change in unrealized gains (losses) related to assets/liabilities held at period end
(2)
1 
(2)
0 
Union Electric Company |
Uranium
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
(7)
(3)
(6)
(2)
Included in regulatory assets/liabilities
3 
 
(1)
(2)
Purchases
 
(2)
 
(2)
Settlements
1 
 
4 
1 
Ending balance
(3)
(5)
(3)
(5)
Change in unrealized gains (losses) related to assets/liabilities held at period end
3 
(2)
0 
(2)
Union Electric Company |
Natural Gas
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
0 
(1)
0 
0 
Included in regulatory assets/liabilities
0 
   
 
 
Purchases
 
1 
0 
0 
Ending balance
0 
0 
0 
0 
Change in unrealized gains (losses) related to assets/liabilities held at period end
   
   
 
 
Union Electric Company |
Power
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
15 
37 
19 
11 
Included in regulatory assets/liabilities
(5)
(3)
(23)
3 
Purchases
 
 
34 
40 
Sales
 
1 
 
1 
Settlements
(5)
(6)
(25)
(28)
Transfers into Level 3
 
(1)
 
(3)
Transfer out of Level 3
 
 
 
4 
Ending balance
5 
28 
5 
28 
Change in unrealized gains (losses) related to assets/liabilities held at period end
(6)
(2)
(3)
 
Ameren Illinois Company |
Natural Gas
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
0 
2 
0 
0 
Included in regulatory assets/liabilities
1 
(2)
1 
(1)
Purchases
 
0 
(1)
1 
Settlements
 
 
1 
 
Ending balance
1 
0 
1 
0 
Change in unrealized gains (losses) related to assets/liabilities held at period end
   
(1)
 
 
Ameren Illinois Company |
Power
 
 
 
 
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
 
 
 
 
Beginning balance
(103)
(80)
(108)
(111)
Included in regulatory assets/liabilities
(23)
(17)
(19)
(2)
Settlements
2 
3 
3 
19 
Transfers into Level 3
 
   
 
 
Ending balance
(124)
(94)
(124)
(94)
Change in unrealized gains (losses) related to assets/liabilities held at period end
$ (22)
$ (16)
$ (21)
$ (7)
Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended 3 Months Ended
Sep. 30, 2013
Sep. 30, 2013
Fuel Oils
Transfer Into Or Out Of Level One [Member]
Mar. 31, 2012
Fuel Oils
Transfer Into Or Out Of Level One [Member]
Sep. 30, 2013
Natural Gas
Transfer Into/Out of Level 2
Sep. 30, 2013
Power
Sep. 30, 2013
Power
Sep. 30, 2013
Power
Transfer Into/Out of Level 2
Sep. 30, 2013
Power
Transfer Into/Out of Level 2
Sep. 30, 2013
Union Electric Company
Power
Sep. 30, 2013
Union Electric Company
Power
Sep. 30, 2013
Union Electric Company
Power
Transfer Into/Out of Level 2
Sep. 30, 2013
Union Electric Company
Power
Transfer Into/Out of Level 2
Sep. 30, 2013
Ameren Illinois Company
Power
Derivative [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets Transfers into Level 3
 
    
 
 
$ (1)
$ (3)
$ (1)
$ (3)
$ (1)
$ (3)
$ (1)
$ (3)
    
Assets Transfers out of Level 3
 
 
   
   
 
4 
   
4 
 
4 
 
4 
 
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Transfers, Net
$ (1)
 
 
 
 
 
 
 
 
 
 
 
 
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
Sep. 30, 2014
Dec. 31, 2013
Fair Value
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
$ 6,647 1
$ 6,584 1
Preferred stock
122 1
118 1
Fair Value |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
4,466 
4,124 
Preferred stock
73 
71 
Fair Value |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
2,181 
2,028 
Preferred stock
49 
47 
Carrying Amount
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
5,944 1
6,038 1
Preferred stock
142 1
142 1
Carrying Amount |
Union Electric Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
4,004 
3,757 
Preferred stock
80 
80 
Carrying Amount |
Ameren Illinois Company
 
 
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
 
 
Long-term debt (including current portion)
1,940 
1,856 
Preferred stock
$ 62 
$ 62 
Related Party Transactions Narrative (Details) (Ameren Illinois Company, Ameren Illinois Power Supply Agreements with Ameren Missouri)
9 Months Ended
Sep. 30, 2014
MWh
Ameren Illinois Company |
Ameren Illinois Power Supply Agreements with Ameren Missouri
 
Related Party Transaction [Line Items]
 
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power
168,400 
Long-term Contract for Purchase of Electric Power, Related Party Contract, Fixed Power, Rate
51 
Commitments And Contingencies (Callaway Energy Center) (Detail) (USD $)
9 Months Ended
Sep. 30, 2014
Commitments And Contingencies [Line Items]
 
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
19,000,000 
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act
128,000,000 
Maximum annual payment in calendar year per reactor incident under Price Andersen Liability Provisions of Atomic Energy Act
19,000,000 
Amount of coverage in excess of primary property liability coverage
2,250,000,000.00 
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
1 year 
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage
3,600,000 
Number of additional weeks after initial indemnity coverage for power outage, minimum
1 year 4 months 10 days 
Amount of secondary weekly indemnity coverage for prolonged nuclear plant outage in excess of primary indemnity coverage
900,000 
Inflationary adjustment prescribed by most recent Price-Anderson Act renewal, in years
5 years 
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period
3,240,000,000 
Public Liability
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
13,616,000,000 1
Maximum Assessments for Single Incidents
128,000,000 
Public Liability And Nuclear Worker Liability - American Nuclear Insurers [Member]
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
375,000,000 
Public Liability And Nuclear Worker Liability - Pool Participation [Member]
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
13,241,000,000 2
Maximum Assessments for Single Incidents
128,000,000 3
Property Damage
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
2,750,000,000 
Maximum Assessments for Single Incidents
23,000,000 
Property Damage - Nuclear Electric Insurance Ltd [Member]
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
2,250,000,000 4
Maximum Assessments for Single Incidents
23,000,000 5
Property Damage European Mutual Association for Nuclear Insurance [Member]
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
500,000,000 6
Amount of primary property liability coverage
500,000,000 
Replacement Power - Nuclear Electric Insurance Ltd [Member]
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
490,000,000 7
Maximum Assessments for Single Incidents
9,000,000 5
Amount of weekly indemnity coverage thereafter not exceeding policy limit
490,000,000 
Sub-limit of for non-nuclear events
327,600,000 
Replacement Power - Energy Risk Assurance Company [Member]
 
Commitments And Contingencies [Line Items]
 
Maximum Coverages
64,000,000 8
Amount of weekly indemnity coverage thereafter not exceeding policy limit
3,600,000 
Non-radiation event [Member]
 
Commitments And Contingencies [Line Items]
 
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period
$ 1,830,000,000 
Commitments And Contingencies (Other Obligations) (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Long-term Purchase Commitment [Line Items]
 
2014
$ 457 1
2015
1,265 1
2016
1,040 1
2017
941 1
2018
324 1
Thereafter
1,480 1
Total
5,507 1
Renewable Energy Credits Agreements, Term
20 years 
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
294 
2015
864 
2016
813 
2017
805 
2018
233 
Thereafter
716 
Total
3,725 
Ameren Illinois Company
 
Long-term Purchase Commitment [Line Items]
 
2014
144 
2015
383 
2016
214 
2017
136 
2018
91 
Thereafter
764 
Total
1,732 
Investment in Energy Efficiency Programs |
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
17 
2015
64 
Coal
 
Long-term Purchase Commitment [Line Items]
 
2014
151 1
2015
635 1
2016
659 1
2017
682 1
2018
111 1
Thereafter
114 1
Total
2,352 1
Coal |
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
151 
2015
635 
2016
659 
2017
682 
2018
111 
Thereafter
114 
Total
2,352 
Coal |
Ameren Illinois Company
 
Long-term Purchase Commitment [Line Items]
 
2014
   
2015
   
2016
   
2017
   
2018
   
Thereafter
   
Total
   
Natural Gas
 
Long-term Purchase Commitment [Line Items]
 
2014
93 1 2
2015
225 1 2
2016
127 1 2
2017
80 1 2
2018
41 1 2
Thereafter
101 1 2
Total
667 1 2
Natural Gas |
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
16 2
2015
39 2
2016
21 2
2017
13 2
2018
8 2
Thereafter
29 2
Total
126 2
Natural Gas |
Ameren Illinois Company
 
Long-term Purchase Commitment [Line Items]
 
2014
77 2
2015
186 2
2016
106 2
2017
67 2
2018
33 2
Thereafter
72 2
Total
541 2
Nuclear Fuel
 
Long-term Purchase Commitment [Line Items]
 
2014
62 1
2015
56 1
2016
69 1
2017
59 1
2018
61 1
Thereafter
179 1
Total
486 1
Nuclear Fuel |
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
62 
2015
56 
2016
69 
2017
59 
2018
61 
Thereafter
179 
Total
486 
Nuclear Fuel |
Ameren Illinois Company
 
Long-term Purchase Commitment [Line Items]
 
2014
   
2015
   
2016
   
2017
   
2018
   
Thereafter
   
Total
   
Purchased Power
 
Long-term Purchase Commitment [Line Items]
 
2014
62 1 3
2015
190 1 3
2016
105 1 3
2017
66 1 3
2018
55 1 3
Thereafter
645 1 3
Total
1,123 1 3
Purchased Power |
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
4 
2015
21 
2016
21 
2017
21 
2018
21 
Thereafter
120 
Total
208 
Purchased Power |
Ameren Illinois Company
 
Long-term Purchase Commitment [Line Items]
 
2014
58 3
2015
169 3
2016
84 3
2017
45 3
2018
34 3
Thereafter
525 3
Total
915 3
Methane Gas
 
Long-term Purchase Commitment [Line Items]
 
2014
1 1
2015
3 1
2016
4 1
2017
4 1
2018
5 1
Thereafter
91 1
Total
108 1
Methane Gas |
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
1 
2015
3 
2016
4 
2017
4 
2018
5 
Thereafter
91 
Total
108 
Methane Gas |
Ameren Illinois Company
 
Long-term Purchase Commitment [Line Items]
 
2014
   
2015
   
2016
   
2017
   
2018
   
Thereafter
   
Total
   
Other Commitments
 
Long-term Purchase Commitment [Line Items]
 
2014
88 1
2015
156 1
2016
76 1
2017
50 1
2018
51 1
Thereafter
350 1
Total
771 1
Other Commitments |
Union Electric Company
 
Long-term Purchase Commitment [Line Items]
 
2014
60 
2015
110 
2016
39 
2017
26 
2018
27 
Thereafter
183 
Total
445 
Other Commitments |
Ameren Illinois Company
 
Long-term Purchase Commitment [Line Items]
 
2014
9 
2015
28 
2016
24 
2017
24 
2018
24 
Thereafter
167 
Total
$ 276 
Commitments And Contingencies (Environmental Matters) (Detail) (USD $)
9 Months Ended
Sep. 30, 2014
Loss Contingencies [Line Items]
 
EPA Clean Power Plan CO2 Proposed Reductions
30.00% 
Estimated Environmental Expenditures to Comply with Clean Power Plan
$ 2,000,000,000 
Minimum
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
325,000,000 
Maximum
 
Loss Contingencies [Line Items]
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
375,000,000 
Former Coal Tar Distillery |
Union Electric Company
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
2,000,000 
Range of possible loss maximum
5,000,000 
Accrual for environmental loss contingencies
2,000,000 
Former Coal Ash Landfill |
Ameren Illinois Company
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
500,000 
Range of possible loss maximum
6,000,000 
Accrual for environmental loss contingencies
500,000 
Manufactured Gas Plant
 
Loss Contingencies [Line Items]
 
Accrual for environmental loss contingencies
254,000,000 
Manufactured Gas Plant |
Ameren Illinois Company
 
Loss Contingencies [Line Items]
 
Number of remediation sites
44 
Range of possible loss, minimum
254,000,000 
Range of possible loss maximum
316,000,000 
Accrual for environmental loss contingencies
254,000,000 
Other Environmental |
Ameren Illinois Company
 
Loss Contingencies [Line Items]
 
Accrual for environmental loss contingencies
700,000 
Sauget Area Two |
Union Electric Company
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
1,000,000 
Range of possible loss maximum
2,500,000 
Accrual for environmental loss contingencies
1,000,000 
Substation in St Charles, Missouri |
Union Electric Company
 
Loss Contingencies [Line Items]
 
Range of possible loss, minimum
2,200,000 
Range of possible loss maximum
4,500,000 
Accrual for environmental loss contingencies
$ 2,200,000 
Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Detail) (Union Electric Company, USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2014
Union Electric Company
 
Loss Contingencies [Line Items]
 
Litigation Settlement, Amount
$ 27 
Insurance settlements receivable
$ 41 
Callaway Energy Center (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended 12 Months Ended
Sep. 30, 2014
mill
Dec. 31, 2013
Dec. 31, 2012
Dec. 31, 2011
Nuclear Waste Matters [Line Items]
 
 
 
 
Miscellaneous accounts and notes receivable
$ 117 
$ 196 
 
 
Nuclear Plant [Member]
 
 
 
 
Nuclear Waste Matters [Line Items]
 
 
 
 
Number of mills charged for NWF fee
1 
 
 
 
Miscellaneous accounts and notes receivable
15 
15 
 
 
Assumed life of plant, in years
40 years 
 
 
 
Annual decommissioning costs included in costs of service
 
$ 7 
$ 7 
$ 7 
Minimum |
Nuclear Plant [Member]
 
 
 
 
Nuclear Waste Matters [Line Items]
 
 
 
 
Number of mills charged for NWF fee
0 
 
 
 
Retirement Benefits (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
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
$ 340 
Minimum
 
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
40 
Maximum
 
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
$ 110 
Retirement Benefits (Components Of Net Periodic Benefit Cost) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Pension Plan, Defined Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Service cost
$ 20 
$ 23 
$ 60 
$ 69 
Interest cost
46 
40 
137 
121 
Expected return on plan assets
(58)
(54)
(172)
(162)
Prior service cost (benefit)
(1)
(1)
(1)
(3)
Actuarial loss
13 
23 
37 
69 
Net periodic benefit cost
20 
31 1
61 
94 1
Postretirement Benefit Costs [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Service cost
5 
6 
14 
17 
Interest cost
12 
11 
37 
34 
Expected return on plan assets
(16)
(16)
(48)
(47)
Prior service cost (benefit)
(2)
(1)
(4)
(3)
Actuarial loss
(2)
2 
(5)
6 
Net periodic benefit cost
(3)
2 1
(6)
7 1
Other Postretirement Benefit Plan, Defined Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
(3)2
2 2
(6)2
7 2
Other Postretirement Benefit Plan, Defined Benefit [Member] |
New Ameren Energy Resources Company, LLC
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
 
1 3
 
1 3
Pension Plan, Defined Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
20 2
31 2
61 2
94 2
Pension Plan, Defined Benefit [Member] |
New Ameren Energy Resources Company, LLC
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
 
$ 2 
 
$ 8 
Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Pension Plan, Defined Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
$ 20 1
$ 31 1
$ 61 1
$ 94 1
Pension Plan, Defined Benefit [Member] |
Union Electric Company
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
13 
18 
38 
54 
Pension Plan, Defined Benefit [Member] |
Ameren Illinois Company
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
7 
10 
22 
31 
Pension Plan, Defined Benefit [Member] |
Other
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
1 2
3 3
1 
9 3
Other Postretirement Benefit Plan, Defined Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
(3)1
2 1
(6)1
7 1
Other Postretirement Benefit Plan, Defined Benefit [Member] |
Union Electric Company
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
1 2
2 
2 
7 
Other Postretirement Benefit Plan, Defined Benefit [Member] |
Ameren Illinois Company
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
(3)
1 2
(7)
1 2
Other Postretirement Benefit Plan, Defined Benefit [Member] |
Other
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
1 2
1 2 3
(1)
1 2 3
New Ameren Energy Resources Company, LLC |
Pension Plan, Defined Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
 
2 
 
8 
New Ameren Energy Resources Company, LLC |
Other Postretirement Benefit Plan, Defined Benefit [Member]
 
 
 
 
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
 
 
 
 
Net periodic benefit cost
 
$ 1 2
 
$ 1 2
Divestiture Transactions and Discontinued Operations (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
9 Months Ended 1 Months Ended 3 Months Ended
Sep. 30, 2014
Sep. 30, 2014
New Ameren Energy Resources Company, LLC
Sep. 30, 2013
New Ameren Energy Resources Company, LLC
Mar. 14, 2013
New Ameren Energy Resources Company, LLC
Sep. 30, 2014
Notes Payable, Other Payables [Member]
New Ameren Energy Resources Company, LLC
Dec. 31, 2013
Notes Payable, Other Payables [Member]
New Ameren Energy Resources Company, LLC
Jan. 31, 2014
Elgin, Gibson City and Grand Tower Energy Centers
Dec. 31, 2013
Elgin, Gibson City and Grand Tower Energy Centers
Sep. 30, 2014
Ameren Energy Marketing Company [Member]
Sep. 30, 2014
Guarantee Type, Other [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
 
 
 
 
 
 
Escrow Deposit, Reserve Period
2 years 
 
 
 
 
 
 
 
 
 
Proceeds from Sales of Business, Affiliate and Productive Assets
 
 
 
 
 
 
$ 168.0 
$ 137.5 
 
 
Proceeds from Asset Sale Held in Escrow
 
 
 
 
 
 
17 
 
 
 
Impairment of assets to be disposed of
 
 
175 
 
 
 
 
 
 
 
Discontinued operations deferred tax expense
 
 
96 
 
 
 
 
 
 
 
Discontinued operations deferred tax benefit
 
 
72 
 
 
 
 
 
 
 
Working Capital and Contingent Liability Payment
 
13 
 
 
 
 
 
 
 
 
Range of possible loss maximum
 
29.0 
 
 
 
 
 
 
 
 
Notes, Loans and Financing Receivable, Net, Noncurrent
 
 
 
 
23 
18 
 
 
 
 
Collateral to be posted if credit ratings are below investment grade
 
23 
 
 
 
 
 
 
 
 
Buyer's indemnification guarantee obligation
 
 
 
25 
 
 
 
 
 
 
Loss contingency accrual
 
29 
 
 
 
 
 
 
 
 
Guarantees Outstanding
 
141 
 
 
 
 
 
 
132 
9 
Guarantees, Maximum Exposure
 
 
 
 
 
 
 
 
4 
8 
Letters of Credit Outstanding, Amount
 
$ 9 
 
 
 
 
 
 
 
 
Divestiture Transactions and Discontinued Operations (Components of Discontinued Operations in Consolidated Statement of Income) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
Operating revenues
$ 0 
$ 311 
$ 1 
$ 878 
Operating expenses
(1)
(309)
(4)
(1,034)1
Operating income (loss)
(1)
2 
(3)
(156)
Other income (loss)
   
   
   
(1)
Interest charges
0 
(9)
   
(31)
Loss before income taxes
(1)
(7)
(3)
(188)
Income tax (expense) benefit
0 
4 
   
(24)
Loss from discontinued operations, net of taxes
(1)
(3)
(3)
(212)
New Ameren Energy Resources Company, LLC
 
 
 
 
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
 
 
 
 
Impairment of Long-Lived Assets to be Disposed of
 
 
 
$ 175 
Divestiture Transactions and Discontinued Operations (Components of Assets and Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2014
Dec. 31, 2013
Sep. 30, 2013
Assets of discontinued operations
 
 
 
Cash and cash equivalents
    
    
$ 25 
Accounts receivable and unbilled revenue
   
5 
 
Materials and supplies
   
5 
 
Property and plant, net
   
142 
 
Accumulated deferred income taxes, net(a)
15 1
13 1
 
Total assets of discontinued operations
15 
165 
 
Liabilities of discontinued operations
 
 
 
Accounts payable and other current obligations
1 
5 
 
Asset retirement obligations
32 2
40 2
 
Total liabilities of discontinued operations
33 
45 
 
Asset retirement obligations
385 
369 
 
Shutdown Of Meredosia And Hutsonville Energy Centers [Member]
 
 
 
Liabilities of discontinued operations
 
 
 
Asset retirement obligations
$ 32 
$ 31 
 
Segment Information (Schedule Of Segment Reporting Information By Segment) (Detail) (USD $)
3 Months Ended 9 Months Ended
Sep. 30, 2014
Sep. 30, 2013
Sep. 30, 2014
Sep. 30, 2013
Dec. 31, 2013
Segment Reporting Information [Line Items]
 
 
 
 
 
Number of Reportable Segments
 
 
2 
 
 
External revenues
$ 1,670,000,000 
$ 1,638,000,000 
$ 4,683,000,000 
$ 4,516,000,000 
 
Net income (loss) attributable to Ameren Corporation from continuing operations
294,000,000 
305,000,000 
541,000,000 
464,000,000 
 
Total assets
21,876,000,000 
 
21,876,000,000 
 
21,042,000,000 
Assets of discontinued operations (Note 12)
15,000,000 
 
15,000,000 
 
165,000,000 
Union Electric Company
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
1,089,000,000 
1,088,000,000 
2,793,000,000 
2,760,000,000 
 
Intersegment revenues
8,000,000 
5,000,000 
21,000,000 
18,000,000 
 
Net income (loss) attributable to Ameren Corporation from continuing operations
222,000,000 
238,000,000 
395,000,000 
362,000,000 
 
Total assets
13,179,000,000 
 
13,179,000,000 
 
12,904,000,000 
Ameren Illinois Company
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
572,000,000 
547,000,000 
1,864,000,000 
1,744,000,000 
 
Intersegment revenues
   
   
1,000,000 
3,000,000 
 
Net income (loss) attributable to Ameren Corporation from continuing operations
75,000,000 
77,000,000 
156,000,000 
139,000,000 
 
Total assets
7,983,000,000 
 
7,983,000,000 
 
7,454,000,000 
Other
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
9,000,000 
3,000,000 
26,000,000 
12,000,000 
 
Intersegment revenues
2,000,000 
1,000,000 
3,000,000 
2,000,000 
 
Net income (loss) attributable to Ameren Corporation from continuing operations
(3,000,000)
(10,000,000)
(10,000,000)
(37,000,000)
 
Total assets
810,000,000 
 
810,000,000 
 
752,000,000 
Intersegment Eliminations
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
   
   
   
   
 
Intersegment revenues
(10,000,000)
(6,000,000)
(25,000,000)
(23,000,000)
 
Net income (loss) attributable to Ameren Corporation from continuing operations
   
   
   
   
 
Total assets
(111,000,000)
 
(111,000,000)
 
(233,000,000)
Consolidated, Continuing Operations
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
External revenues
1,670,000,000 
1,638,000,000 
4,683,000,000 
4,516,000,000 
 
Intersegment revenues
   
   
   
   
 
Net income (loss) attributable to Ameren Corporation from continuing operations
294,000,000 
305,000,000 
541,000,000 
464,000,000 
 
Total assets
$ 21,861,000,000 1
 
$ 21,861,000,000 1
 
$ 20,877,000,000 1