UNION ELECTRIC CO, 10-Q filed on 8/9/2011
Quarterly Report
Document and Entity Information
6 Months Ended
Jun. 30, 2011
Jul. 29, 2011
Document Type
10-Q 
 
Amendment Flag
FALSE 
 
Document Period End Date
Jun. 30, 2011 
 
Document Fiscal Year Focus
2011 
 
Document Fiscal Period Focus
Q2 
 
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 
 
Ameren Corporation [Member]
 
 
Entity Common Stock, Shares Outstanding
 
241,666,357 
Union Electric Company [Member]
 
 
Document Type
10-Q 
 
Amendment Flag
FALSE 
 
Document Period End Date
Jun. 30, 2011 
 
Document Fiscal Year Focus
2011 
 
Document Fiscal Period Focus
Q2 
 
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 [Member]
 
 
Document Type
10-Q 
 
Amendment Flag
FALSE 
 
Document Period End Date
Jun. 30, 2011 
 
Document Fiscal Year Focus
2011 
 
Document Fiscal Period Focus
Q2 
 
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 
Ameren Energy Generating Company [Member]
 
 
Document Type
10-Q 
 
Amendment Flag
FALSE 
 
Document Period End Date
Jun. 30, 2011 
 
Document Fiscal Year Focus
2011 
 
Document Fiscal Period Focus
Q2 
 
Entity Registrant Name
AMEREN ENERGY GENERATING CO 
 
Entity Central Index Key
0001135361 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
2,000 
Consolidated Statement of Income (USD $)
In Millions, except Per Share data
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Operating Revenues:
 
 
 
 
Electric
$ 1,614 
$ 1,552 
$ 3,084 
$ 3,007 
Gas
167 
173 
601 
658 
Total operating revenues
1,781 
1,725 
3,685 
3,665 
Operating Expenses:
 
 
 
 
Fuel
371 
286 
750 
579 
Purchased power
237 
268 
464 
539 
Gas purchased for resale
79 
83 
367 
416 
Other operations and maintenance
475 
465 
938 
902 
Depreciation and amortization
194 
190 
389 
377 
Taxes other than income taxes
109 
102 
234 
223 
Total operating expenses
1,465 
1,394 
3,142 
3,036 
Operating Income
316 
331 
543 
629 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
17 1
24 1
33 1
46 1
Miscellaneous expense
5 1
2 1
10 1
9 1
Total other income
12 
22 
23 
37 
Interest charges
104 
115 
223 
247 
Income Before Income Taxes
224 
238 
343 
419 
Income Taxes
85 
83 
130 
158 
Net Income
139 1
155 1
213 1
261 1
Less: Net Income Attributable to Noncontrolling Interests
1 1
3 1
4 1
7 1
Net Income Attributable to Ameren Corporation
138 2
152 2
209 2
254 2
Earnings per Common Share - Basic and Diluted
$ 0.57 
$ 0.64 
$ 0.87 
$ 1.07 
Dividends per Common Share
$ 0.385 
$ 0.385 
$ 0.77 
$ 0.77 
Average Common Shares Outstanding
241.2 
238.4 
240.9 
238.0 
Union Electric Company [Member]
 
 
 
 
Operating Revenues:
 
 
 
 
Electric
791 
737 
1,493 
1,344 
Gas
28 
23 
97 
98 
Other
3 
1 
4 
1 
Total operating revenues
822 
761 
1,594 
1,443 
Operating Expenses:
 
 
 
 
Fuel
204 
112 
433 
236 
Purchased power
26 
42 
46 
86 
Gas purchased for resale
11 
10 
51 
56 
Other operations and maintenance
231 
240 
464 
458 
Depreciation and amortization
98 
92 
198 
184 
Taxes other than income taxes
76 
68 
149 
136 
Total operating expenses
646 
564 
1,341 
1,156 
Operating Income
176 
197 
253 
287 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
16 
20 
29 
41 
Miscellaneous expense
3 
1 
6 
3 
Total other income
13 
19 
23 
38 
Interest charges
45 
43 
99 
102 
Income Before Income Taxes
144 
173 
177 
223 
Income Taxes
53 
58 
64 
80 
Net Income
91 
115 
113 
143 
Preferred Stock Dividends
1 
2 
2 
3 
Net Income Available to Common Stockholder
90 
113 
111 
140 
Ameren Illinois [Member]
 
 
 
 
Operating Revenues:
 
 
 
 
Electric
483 
497 3
925 
998 3
Gas
139 
150 3
505 
560 3
Other
1 
 
1 
 
Total operating revenues
623 
647 3
1,431 
1,558 3
Operating Expenses:
 
 
 
 
Purchased power
196 
227 3
407 
496 3
Gas purchased for resale
67 
73 3
315 
359 3
Other operations and maintenance
181 
159 3
349 
321 3
Depreciation and amortization
54 
52 3
106 
106 3
Taxes other than income taxes
26 
24 3
67 
66 3
Total operating expenses
524 
535 3
1,244 
1,348 3
Operating Income
99 
112 3
187 
210 3
Other Income and Expenses:
 
 
 
 
Miscellaneous income
1 
2 3
3 
4 3
Miscellaneous expense
1 
1 3
2 
4 3
Total other income
 
1 3
1 
 
Interest charges
35 
34 3
70 
71 3
Income Before Income Taxes
64 
79 3
118 
139 3
Income Taxes
26 
31 3
46 
55 3
Income from Continuing Operations
38 
48 3
72 
84 3
Income from Discontinued Operations, net of tax
 
9 3
 
21 3
Net Income
38 
57 3
72 
105 3
Preferred Stock Dividends
1 
2 3
2 
3 3
Net Income Available to Common Stockholder
37 
55 3
70 
102 3
Ameren Energy Generating Company [Member]
 
 
 
 
Operating Revenues:
 
 
 
 
Total operating revenues
260 
275 
501 
542 
Operating Expenses:
 
 
 
 
Fuel
130 
136 
241 
259 
Purchased power
18 
18 
18 
20 
Other operations and maintenance
45 
45 
90 
94 
Depreciation and amortization
25 
25 
49 
49 
Taxes other than income taxes
5 
6 
12 
13 
Total operating expenses
223 
230 
410 
435 
Operating Income
37 
45 
91 
107 
Other Income and Expenses:
 
 
 
 
Miscellaneous income
 
1 
 
1 
Miscellaneous expense
 
 
 
1 
Total other income
 
1 
 
 
Interest charges
14 
20 
31 
39 
Income Before Income Taxes
23 
26 
60 
68 
Income Taxes
10 
12 
25 
30 
Net Income
13 
14 
35 
38 
Less: Net Income Attributable to Noncontrolling Interests
 
1 
1 
2 
Net Income Attributable to Ameren Corporation
$ 13 
$ 13 
$ 34 
$ 36 
Consolidated Balance Sheet (USD $)
In Millions
Jun. 30, 2011
Dec. 31, 2010
Current Assets:
 
 
Cash and cash equivalents
$ 378 
$ 545 
Accounts receivable - trade (less allowance for doubtful accounts)
507 
500 
Unbilled revenue
368 
406 
Miscellaneous accounts and notes receivable
249 
231 
Materials and supplies
654 
707 
Mark-to-market derivative assets
159 
129 
Current regulatory assets
184 
267 
Other current assets
104 
109 
Total current assets
2,603 
2,894 
Property and Plant, Net
17,945 
17,853 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
356 
337 
Goodwill
411 
411 
Intangible assets
4 
7 
Regulatory assets
1,224 
1,263 
Other assets
848 
750 
Regulated Entity, Other Assets, Noncurrent, Total
2,843 
2,768 
TOTAL ASSETS
23,391 
23,515 
Current Liabilities:
 
 
Current maturities of long-term debt
5 
155 
Short-term debt
337 
269 
Accounts and wages payable
482 
651 
Taxes accrued
139 
63 
Interest accrued
107 
107 
Customer deposits
100 
100 
Mark-to-market derivative liabilities
135 
161 
Current regulatory liabilities
160 
99 
Other current liabilities
262 
283 
Total current liabilities
1,727 
1,888 
Credit Facility Borrowings
200 
460 
Long-term Debt, Net
6,854 
6,853 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
3,121 
2,886 
Accumulated deferred investment tax credits
87 
90 
Regulatory liabilities
1,424 
1,319 
Asset retirement obligations
487 
475 
Pension and other postretirement benefits
1,067 
1,045 
Other deferred credits and liabilities
481 
615 
Total deferred credits and other liabilities
6,667 
6,430 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
 
 
Stockholders' Equity:
 
 
Common stock
2 
2 
Other paid-in capital
5,559 
5,520 
Retained earnings
2,248 
2,225 
Accumulated other comprehensive loss
(21)
(17)
Total stockholders' equity
7,788 
7,730 
Noncontrolling Interests
155 
154 
Total equity
7,943 
7,884 
TOTAL LIABILITIES AND EQUITY
23,391 
23,515 
Union Electric Company [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
79 
202 
Accounts receivable - trade (less allowance for doubtful accounts)
236 
217 
Accounts receivable - affiliates
10 
6 
Unbilled revenue
200 
159 
Miscellaneous accounts and notes receivable
71 
116 
Materials and supplies
343 
341 
Mark-to-market derivative assets
58 
35 
Current regulatory assets
114 
179 
Other current assets
14 
20 
Total current assets
1,125 
1,275 
Property and Plant, Net
9,862 
9,775 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
356 
337 
Intangible assets
4 
2 
Regulatory assets
691 
694 
Other assets
489 
421 
Regulated Entity, Other Assets, Noncurrent, Total
1,540 
1,454 
TOTAL ASSETS
12,527 
12,504 
Current Liabilities:
 
 
Current maturities of long-term debt
5 
5 
Accounts and wages payable
179 
326 
Accounts payable - affiliates
55 
75 
Taxes accrued
134 
76 
Interest accrued
73 
63 
Current accumulated deferred income taxes, net
18 
43 
Current regulatory liabilities
70 
23 
Other current liabilities
90 
89 
Total current liabilities
624 
700 
Long-term Debt, Net
3,949 
3,949 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
2,027 
1,908 
Accumulated deferred investment tax credits
76 
78 
Regulatory liabilities
801 
766 
Asset retirement obligations
373 
363 
Pension and other postretirement benefits
371 
369 
Other deferred credits and liabilities
176 
218 
Total deferred credits and other liabilities
3,824 
3,702 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
 
 
Stockholders' Equity:
 
 
Common stock
511 
511 
Other paid-in capital
1,555 
1,555 
Preferred stock not subject to mandatory redemption
80 
80 
Retained earnings
1,984 
2,007 
Total stockholders' equity
4,130 
4,153 
TOTAL LIABILITIES AND EQUITY
12,527 
12,504 
Ameren Illinois [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
253 
322 
Accounts receivable - trade (less allowance for doubtful accounts)
197 
230 
Accounts receivable - affiliates
21 
73 
Unbilled revenue
129 
205 
Miscellaneous accounts and notes receivable
104 
44 
Materials and supplies
145 
198 
Current regulatory assets
243 
260 
Other current assets
109 
106 
Total current assets
1,201 
1,438 
Property and Plant, Net
4,657 
4,576 
Investments and Other Assets:
 
 
Tax receivable - Genco
64 
72 
Goodwill
411 
411 
Regulatory assets
628 
747 
Other assets
193 
162 
Regulated Entity, Other Assets, Noncurrent, Total
1,296 
1,392 
TOTAL ASSETS
7,154 
7,406 
Current Liabilities:
 
 
Current maturities of long-term debt
 
150 
Accounts and wages payable
185 
182 
Accounts payable - affiliates
65 
82 
Taxes accrued
47 
26 
Customer deposits
82 
83 
Mark-to-market derivative liabilities
64 
82 
Mark-to-market derivative liabilities - affiliates
173 
172 
Environmental remediation
55 
72 
Current regulatory liabilities
90 
76 
Other current liabilities
77 
90 
Total current liabilities
838 
1,015 
Long-term Debt, Net
1,658 
1,657 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
807 
724 
Accumulated deferred investment tax credits
7 
8 
Regulatory liabilities
623 
553 
Pension and other postretirement benefits
446 
413 
Other deferred credits and liabilities
282 
460 
Total deferred credits and other liabilities
2,165 
2,158 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
 
 
Stockholders' Equity:
 
 
Common stock
 
 
Other paid-in capital
1,952 
1,952 
Preferred stock not subject to mandatory redemption
62 
62 
Retained earnings
461 
542 
Accumulated other comprehensive loss
18 
20 
Total stockholders' equity
2,493 
2,576 
TOTAL LIABILITIES AND EQUITY
7,154 
7,406 
Ameren Energy Generating Company [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
7 
6 
Advances to money pool
 
25 
Accounts receivable - affiliates
98 
126 
Miscellaneous accounts and notes receivable
54 
19 
Materials and supplies
121 
130 
Mark-to-market derivative assets
20 
26 
Other current assets
10 
4 
Total current assets
310 
336 
Property and Plant, Net
2,237 
2,248 
Investments and Other Assets:
 
 
Intangible assets
 
3 
Other assets
22 
24 
TOTAL ASSETS
2,569 
2,611 
Current Liabilities:
 
 
Accounts and wages payable
64 
62 
Accounts payable - affiliates
25 
23 
Current portion of tax payable - Ameren Illinois
11 
8 
Taxes accrued
21 
20 
Interest accrued
13 
13 
Mark-to-market derivative liabilities
5 
9 
Mark-to-market derivative liabilities - affiliates
1 
5 
Current accumulated deferred income taxes, net
17 
13 
Other current liabilities
10 
12 
Total current liabilities
167 
165 
Credit Facility Borrowings
 
100 
Long-term Debt, Net
824 
824 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
290 
253 
Accumulated deferred investment tax credits
3 
3 
Tax payable - Ameren Illinois
64 
72 
Asset retirement obligations
75 
74 
Pension and other postretirement benefits
84 
88 
Other deferred credits and liabilities
17 
23 
Total deferred credits and other liabilities
533 
513 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
 
 
Stockholders' Equity:
 
 
Common stock
 
 
Other paid-in capital
649 
649 
Retained earnings
427 
393 
Accumulated other comprehensive loss
(43)
(44)
Total stockholders' equity
1,033 
998 
Noncontrolling Interests
12 
11 
Total equity
1,045 
1,009 
TOTAL LIABILITIES AND EQUITY
$ 2,569 
$ 2,611 
Consolidated Balance Sheet (Parenthetical) (USD $)
In Millions, except Share data
Jun. 30, 2011
Dec. 31, 2010
Accounts receivable - trade, allowance for doubtful accounts
$ 25 
$ 23 
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
400,000,000 
400,000,000 
Common stock, shares outstanding
241,600,000 
240,400,000 
Union Electric Company [Member]
 
 
Accounts receivable - trade, allowance for doubtful accounts
8 
8 
Common stock, par value
$ 5 
$ 5 
Common stock, shares authorized
150,000,000 
150,000,000 
Common stock, shares outstanding
102,100,000 
102,100,000 
Ameren Illinois [Member]
 
 
Accounts receivable - trade, allowance for doubtful accounts
$ 16 
$ 13 
Common stock, no par value
 
 
Common stock, shares authorized
45,000,000 
45,000,000 
Common stock, shares outstanding
25,500,000 
25,500,000 
Ameren Energy Generating Company [Member]
 
 
Common stock, no par value
 
 
Common stock, shares authorized
10,000 
10,000 
Common stock, shares outstanding
2,000 
2,000 
Consolidated Statement of Cash Flows (USD $)
In Millions
6 Months Ended
Jun. 30,
2011
2010
Cash Flows From Operating Activities:
 
 
Net income
$ 213 1
$ 261 1
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Gain on sales of properties
(11)
(5)
Net mark-to-market (gain) loss on derivatives
(5)
 
Depreciation and amortization
391 
387 
Amortization of nuclear fuel
34 
19 
Amortization of debt issuance costs and premium/discounts
12 
12 
Deferred income taxes and investment tax credits, net
221 
175 
Allowance for equity funds used during construction
(15)1
(26)1
Other
10 
5 
Changes in assets and liabilities:
 
 
Receivables
(55)
(36)
Materials and supplies
55 
108 
Accounts and wages payable
(133)
(125)
Taxes accrued
76 
75 
Assets, other
60 
(99)
Liabilities, other
(3)
 
Pension and other postretirement benefits
31 
33 
Counterparty collateral, net
23 
(69)
Taum Sauk insurance recoveries, net of costs
(1)
56 
Net cash provided by operating activities
903 
771 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(507)
(547)
Nuclear fuel expenditures
(33)
(22)
Purchases of securities - nuclear decommissioning trust fund
(125)
(118)
Sales of securities - nuclear decommissioning trust fund
113 
110 
Proceeds from sales of properties
49 
20 
Other
5 
(3)
Net cash used in investing activities
(498)
(560)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(186)
(183)
Dividends paid to noncontrolling interest holders
(3)
(5)
Short-term and credit facility repayments, net
(192)
(160)
Maturities of long-term debt
(150)
 
Issuances of common stock
32 
43 
Generator advances for construction refunded, net of receipts
(73)
(22)
Net cash used in financing activities
(572)
(327)
Net change in cash and cash equivalents
(167)
(116)
Cash and cash equivalents at beginning of year
545 
622 
Cash and cash equivalents at end of period
378 
506 
Noncash investing activity - DOE Settlement (Note 10)
9 
 
Union Electric Company [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income
113 
143 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Net mark-to-market (gain) loss on derivatives
1 
 
Depreciation and amortization
198 
184 
Amortization of nuclear fuel
34 
19 
Amortization of debt issuance costs and premium/discounts
3 
 
Deferred income taxes and investment tax credits, net
86 
106 
Allowance for equity funds used during construction
(14)
(25)
Other
 
(2)
Changes in assets and liabilities:
 
 
Receivables
(82)
(97)
Materials and supplies
(2)
22 
Accounts and wages payable
(136)
(158)
Taxes accrued
58 
125 
Assets, other
57 
(137)
Liabilities, other
23 
39 
Pension and other postretirement benefits
15 
12 
Taum Sauk insurance recoveries, net of costs
(1)
56 
Net cash provided by operating activities
353 
287 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(272)
(321)
Nuclear fuel expenditures
(33)
(22)
Purchases of securities - nuclear decommissioning trust fund
(125)
(118)
Sales of securities - nuclear decommissioning trust fund
113 
110 
Other
(3)
 
Net cash used in investing activities
(320)
(351)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(135)
(116)
Dividends on preferred stock
(2)
(3)
Generator advances for construction refunded, net of receipts
(19)
7 
Net cash used in financing activities
(156)
(112)
Net change in cash and cash equivalents
(123)
(176)
Cash and cash equivalents at beginning of year
202 
267 
Cash and cash equivalents at end of period
79 
91 
Noncash investing activity - DOE Settlement (Note 10)
9 
 
Ameren Illinois [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income
72 
105 2
Income from discontinued operations, net of tax
 
(21)2
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
106 
106 2
Amortization of debt issuance costs and premium/discounts
4 
5 2
Deferred income taxes and investment tax credits, net
86 
34 2
Other
(1)
(1)2
Changes in assets and liabilities:
 
 
Receivables
45 
68 2
Materials and supplies
53 
60 2
Accounts and wages payable
(3)
(32)2
Taxes accrued
21 
5 2
Assets, other
32 
(28)2
Liabilities, other
(24)
(27)2
Pension and other postretirement benefits
14 
12 2
Operating cash flows provided by discontinued operations
 
46 2
Net cash provided by operating activities
405 
332 2
Cash Flows From Investing Activities:
 
 
Capital expenditures
(174)
(147)2
Returns from (advances to) ATXI for construction
49 
(6)2
Proceeds from intercompany note receivable - Genco
 
45 2
Net investing activities used in discontinued operations
 
(3)2
Net cash used in investing activities
(125)
(111)2
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(150)
(67)2
Dividends on preferred stock
(2)
(3)2
Maturities of long-term debt
(150)
 
Generator advances for construction refunded, net of receipts
(53)
(29)2
Net financing activities used in discontinued operations
 
(45)2
Capital contribution from parent
6 
 
Net cash used in financing activities
(349)
(144)2
Net change in cash and cash equivalents
(69)
77 2
Cash and cash equivalents at beginning of year
322 
306 2
Cash and cash equivalents at end of period
253 
383 2
Noncash investing activity - asset transfer from ATXI
 
1 2
Ameren Energy Generating Company [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income
35 
38 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Gain on sales of properties
(11)
(5)
Net mark-to-market (gain) loss on derivatives
(6)
4 
Depreciation and amortization
51 
56 
Amortization of debt issuance costs and premium/discounts
1 
2 
Deferred income taxes and investment tax credits, net
39 
31 
Other
1 
 
Changes in assets and liabilities:
 
 
Receivables
(28)
4 
Materials and supplies
9 
17 
Accounts and wages payable
13 
(11)
Taxes accrued
1 
20 
Assets, other
(2)
5 
Liabilities, other
(12)
(17)
Pension and other postretirement benefits
(3)
3 
Net cash provided by operating activities
88 
147 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(84)
(59)
Proceeds from sales of properties
48 
18 
Money pool advances, net
25 
(21)
Net cash used in investing activities
(11)
(62)
Cash Flows From Financing Activities:
 
 
Short-term and credit facility repayments, net
(100)
 
Note payable - affiliates
 
(84)
Capital contribution from parent
24 
 
Net cash used in financing activities
(76)
(84)
Net change in cash and cash equivalents
1 
1 
Cash and cash equivalents at beginning of year
6 
6 
Cash and cash equivalents at end of period
$ 7 
$ 7 
Summary of Significant Accounting Policies
6 Months Ended
Jun. 30, 2011
Summary of Significant Accounting Policies
Text Block 
Ameren Illinois [Member]
 
Summary of Significant Accounting Policies
Text Block 
Ameren Energy Generating Company [Member]
 
Summary of Significant Accounting Policies
Text Block 
Union Electric Company [Member]
 
Summary of Significant Accounting Policies
Text Block 
Summary of Significant Accounting Policies 

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren's primary assets are the common stock of its subsidiaries. Ameren's subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren's principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

 

•  

Ameren Missouri, or Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

 

•  

Ameren Illinois, or Ameren Illinois Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

 

•  

Resources Company, or Ameren Energy Resources Company, LLC, consists of non-rate-regulated operations, including Ameren Energy Generating Company (Genco), AmerenEnergy Resources Generating Company (AERG), Ameren Energy Marketing Company (Marketing Company) and AmerenEnergy Medina Valley Cogen, LLC (Medina Valley). Genco operates a merchant electric generation business in Illinois. Genco has an 80% ownership interest in EEI.

Ameren has various other subsidiaries responsible for activities such as the provision of other shared services.

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The Ameren Illinois Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren's historical cost basis in Ameren Illinois included purchase accounting adjustments related to Ameren's acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distribution as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG's carrying value. Ameren Illinois has segregated AERG's operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. For Ameren's financial statements, AERG's results of operations remain classified as continuing operations. See Note 14 - Discontinued Operations for additional information.

The financial statements of Ameren, Ameren Illinois and Genco are prepared on a consolidated basis. Ameren Missouri has no subsidiaries, and therefore its financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that impacted Genco's year ended December 31, 2010, and three months ended March 31, 2011, consolidated statements of cash flows. For the year ended December 31, 2010, Genco's reported cash flows provided by operating activities were $280 million and cash flows used in financing activities were $251 million. As corrected, Genco's cash flows provided by operating activities were $304 million and cash flows used in financing activities were $275 million. For the three months ended March 31, 2011, Genco's reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected, Genco's cash flows provided by operating activities were $76 million and cash flows provided by financing activities were $24 million. The error was corrected in Genco's six months ended June 30, 2011, consolidated statement of cash flows, included herein. This correction had no impact on Ameren's previously reported consolidated statement of cash flows.

Earnings Per Share

There were no material differences between Ameren's basic and diluted earnings per share amounts for the three months and six months ended June 30, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of June 30, 2011, and changes during the six months ended June 30, 2011, under the Long-term Incentive Plan of 1998, as amended (1998 Plan), and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units(a)      Restricted Shares(b)  
      Share
Units		    

Weighted-average
Fair Value Per Unit

at Grant Date

      Shares    

Weighted-average
Fair Value Per Share

at Grant Date

  

Nonvested at January 1, 2011

      1,142,768      $ 23.96         83,154      $ 49.87   

Granted(c)

      731,962        31.41         -        -   

Dividends

      -        -         518        28.48   

Forfeitures

      (10,261 )      26.14         (560 )      50.45   

Vested(d)

      (131,343 )      30.67         (63,574 )      49.47   

Nonvested at June 30, 2011

      1,733,126      $ 26.58         19,538      $ 51.21   

 

(a) Granted under the 2006 Plan.
(b) Granted under the 1998 Plan.
(c) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2011 under the 2006 Plan.
(d) Shares/units vested due to Ameren attainment of performance goals and 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 January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren's closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $4 million and $2 million for the three months ended June 30, 2011, and 2010, respectively, and a related tax benefit of $2 million and $1 million for the three months ended June 30, 2011, and 2010, respectively. Ameren recorded compensation expense of $7 million for each of the six-month periods ended June 30, 2011, and 2010, respectively, and a related tax benefit of $3 million for each of the six-month periods ended June 30, 2011, and 2010, respectively. As of June 30, 2011, total compensation expense of $27 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 22 months.

Accounting Changes

Disclosures about Fair Value Measurements

See Note 7 - Fair Value Measurements for recently adopted guidance on fair value measurements.

In May 2011, FASB issued authoritative guidance regarding fair value measurements. The guidance amends the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments will not impact the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

 

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance with respect to comprehensive income will not impact the Ameren Companies' results of operations, financial positions, or liquidity or the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amended guidance will only change the presentation of comprehensive income in the financial statements. The new accounting guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of June 30, 2011, Ameren's and Ameren Illinois' goodwill related to the acquisition of IP in 2004 and the acquisition of CILCORP in 2003. We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Intangible Assets. Ameren, Ameren Missouri and Genco classify emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

In July 2011, the EPA issued the CSAPR, which will create new allowances for SO2 and NOx emissions, thereby restricting the use of existing SO2 and NOx allowances to the acid rain program and NOx budget trading program, respectively. In anticipation of the CSAPR announcement, observable market prices for existing emission allowances declined materially. Consequently, during the second quarter of 2011, Ameren and Genco recorded a noncash pretax impairment charge to other operations and maintenance expense of $2 million and $1 million, respectively. Ameren Missouri recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowances, which had no impact to earnings. See Note 9 - Commitments and Contingencies for additional information on emission allowances and the CSAPR.

Emission allowances are charged to fuel expense as they are used in operations. The following table presents amortization expense based on usage of emission allowances, net of gains from emission allowance sales for Ameren, Ameren Missouri and Genco during the three and six months ended June 30, 2011, and 2010. The table below does not include the intangible asset impairment charges referenced above.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren(a)

    $ 1      $ 7      $ 2      $ 10   

AMO

      -        (b )      -        (b ) 

Genco(a)

      1        5        2        8   

AERG(a)

      (b )      2        (b )      2   

 

(a) Includes allowances consumed that were recorded through purchase accounting.
(b) Less than $1 million.

At June 30, 2011, Ameren's and Ameren Missouri's intangible assets also included renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits as of June 30, 2011, was $3 million.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and natural gas customer bills and Ameren Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three and six months ended June 30, 2011 and 2010:

 

      Three Months      Six Months  
      2011      2010      2011      2010  

Ameren

    $ 44       $ 44       $ 95       $ 90   

AMO

      34         33         63         58   

AIC

      10         11         32         32   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2011, was $198 million, $146 million, $33 million, and $16 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2011, that would impact the effective tax rate, if recognized, was $2 million, $2 million, $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

In the second quarter of 2011, final settlement for the 2005 and 2006 years was reached with the Internal Revenue Service, which resulted in the reduction of uncertain tax liabilities by $39 million, $17 million, $12 million and $4 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. Ameren's federal income tax returns for the years 2007 through 2009 are before the Appeals Office of the Internal Revenue Service.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their results of operations, financial position or liquidity.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, Ameren Illinois and Genco increased compared to December 31, 2010, to reflect the accretion of obligations to their fair values.

Noncontrolling Interests

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity in its consolidated balance sheet. Genco's noncontrolling interest comprised the 20% of EEI not owned by Genco. This noncontrolling interest was classified as a component of equity separate from Genco's equity in its consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren and Genco for the three and six months ended June 30, 2011, and 2010, is shown below:

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:

         

Noncontrolling interest, beginning of period

    $ 155      $ 206      $   154      $   204   

Net income attributable to noncontrolling interest

      1        3        4        7   

Dividends paid to noncontrolling interest holders

      (1 )      (3 )      (3 )      (5 ) 

Noncontrolling interest, end of period

    $ 155      $ 206      $ 155      $ 206   

Genco:

         

Noncontrolling interest, beginning of period

    $ 12      $ 10      $ 11      $ 9   

Net income attributable to noncontrolling interest

      -        1        1        2   

Noncontrolling interest, end of period

    $ 12      $ 11      $ 12      $ 11   

Genco Asset Sale

In June 2011, Genco completed the sale of its remaining interest in the Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $45 million from the sale. Genco recognized an $8 million pretax gain during the second quarter of 2011 relating to this sale. Effective with the sale, the power purchase agreements between Marketing Company and the city of Columbia were terminated.

Summary of Significant Accounting Policies 

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren's primary assets are the common stock of its subsidiaries. Ameren's subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren's principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

 

•  

Ameren Missouri, or Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

 

•  

Ameren Illinois, or Ameren Illinois Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

 

•  

Resources Company, or Ameren Energy Resources Company, LLC, consists of non-rate-regulated operations, including Ameren Energy Generating Company (Genco), AmerenEnergy Resources Generating Company (AERG), Ameren Energy Marketing Company (Marketing Company) and AmerenEnergy Medina Valley Cogen, LLC (Medina Valley). Genco operates a merchant electric generation business in Illinois. Genco has an 80% ownership interest in EEI.

Ameren has various other subsidiaries responsible for activities such as the provision of other shared services.

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The Ameren Illinois Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren's historical cost basis in Ameren Illinois included purchase accounting adjustments related to Ameren's acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distribution as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG's carrying value. Ameren Illinois has segregated AERG's operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. For Ameren's financial statements, AERG's results of operations remain classified as continuing operations. See Note 14 - Discontinued Operations for additional information.

The financial statements of Ameren, Ameren Illinois and Genco are prepared on a consolidated basis. Ameren Missouri has no subsidiaries, and therefore its financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that impacted Genco's year ended December 31, 2010, and three months ended March 31, 2011, consolidated statements of cash flows. For the year ended December 31, 2010, Genco's reported cash flows provided by operating activities were $280 million and cash flows used in financing activities were $251 million. As corrected, Genco's cash flows provided by operating activities were $304 million and cash flows used in financing activities were $275 million. For the three months ended March 31, 2011, Genco's reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected, Genco's cash flows provided by operating activities were $76 million and cash flows provided by financing activities were $24 million. The error was corrected in Genco's six months ended June 30, 2011, consolidated statement of cash flows, included herein. This correction had no impact on Ameren's previously reported consolidated statement of cash flows.

Earnings Per Share

There were no material differences between Ameren's basic and diluted earnings per share amounts for the three months and six months ended June 30, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of June 30, 2011, and changes during the six months ended June 30, 2011, under the Long-term Incentive Plan of 1998, as amended (1998 Plan), and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units(a)      Restricted Shares(b)  
      Share
Units		    

Weighted-average
Fair Value Per Unit

at Grant Date

      Shares    

Weighted-average
Fair Value Per Share

at Grant Date

  

Nonvested at January 1, 2011

      1,142,768      $ 23.96         83,154      $ 49.87   

Granted(c)

      731,962        31.41         -        -   

Dividends

      -        -         518        28.48   

Forfeitures

      (10,261 )      26.14         (560 )      50.45   

Vested(d)

      (131,343 )      30.67         (63,574 )      49.47   

Nonvested at June 30, 2011

      1,733,126      $ 26.58         19,538      $ 51.21   

 

(a) Granted under the 2006 Plan.
(b) Granted under the 1998 Plan.
(c) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2011 under the 2006 Plan.
(d) Shares/units vested due to Ameren attainment of performance goals and 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 January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren's closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $4 million and $2 million for the three months ended June 30, 2011, and 2010, respectively, and a related tax benefit of $2 million and $1 million for the three months ended June 30, 2011, and 2010, respectively. Ameren recorded compensation expense of $7 million for each of the six-month periods ended June 30, 2011, and 2010, respectively, and a related tax benefit of $3 million for each of the six-month periods ended June 30, 2011, and 2010, respectively. As of June 30, 2011, total compensation expense of $27 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 22 months.

Accounting Changes

Disclosures about Fair Value Measurements

See Note 7 - Fair Value Measurements for recently adopted guidance on fair value measurements.

In May 2011, FASB issued authoritative guidance regarding fair value measurements. The guidance amends the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments will not impact the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

 

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance with respect to comprehensive income will not impact the Ameren Companies' results of operations, financial positions, or liquidity or the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amended guidance will only change the presentation of comprehensive income in the financial statements. The new accounting guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of June 30, 2011, Ameren's and Ameren Illinois' goodwill related to the acquisition of IP in 2004 and the acquisition of CILCORP in 2003. We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Intangible Assets. Ameren, Ameren Missouri and Genco classify emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

In July 2011, the EPA issued the CSAPR, which will create new allowances for SO2 and NOx emissions, thereby restricting the use of existing SO2 and NOx allowances to the acid rain program and NOx budget trading program, respectively. In anticipation of the CSAPR announcement, observable market prices for existing emission allowances declined materially. Consequently, during the second quarter of 2011, Ameren and Genco recorded a noncash pretax impairment charge to other operations and maintenance expense of $2 million and $1 million, respectively. Ameren Missouri recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowances, which had no impact to earnings. See Note 9 - Commitments and Contingencies for additional information on emission allowances and the CSAPR.

Emission allowances are charged to fuel expense as they are used in operations. The following table presents amortization expense based on usage of emission allowances, net of gains from emission allowance sales for Ameren, Ameren Missouri and Genco during the three and six months ended June 30, 2011, and 2010. The table below does not include the intangible asset impairment charges referenced above.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren(a)

    $ 1      $ 7      $ 2      $ 10   

AMO

      -        (b )      -        (b ) 

Genco(a)

      1        5        2        8   

AERG(a)

      (b )      2        (b )      2   

 

(a) Includes allowances consumed that were recorded through purchase accounting.
(b) Less than $1 million.

At June 30, 2011, Ameren's and Ameren Missouri's intangible assets also included renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits as of June 30, 2011, was $3 million.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and natural gas customer bills and Ameren Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three and six months ended June 30, 2011 and 2010:

 

      Three Months      Six Months  
      2011      2010      2011      2010  

Ameren

    $ 44       $ 44       $ 95       $ 90   

AMO

      34         33         63         58   

AIC

      10         11         32         32   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2011, was $198 million, $146 million, $33 million, and $16 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2011, that would impact the effective tax rate, if recognized, was $2 million, $2 million, $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

In the second quarter of 2011, final settlement for the 2005 and 2006 years was reached with the Internal Revenue Service, which resulted in the reduction of uncertain tax liabilities by $39 million, $17 million, $12 million and $4 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. Ameren's federal income tax returns for the years 2007 through 2009 are before the Appeals Office of the Internal Revenue Service.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their results of operations, financial position or liquidity.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, Ameren Illinois and Genco increased compared to December 31, 2010, to reflect the accretion of obligations to their fair values.

Noncontrolling Interests

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity in its consolidated balance sheet. Genco's noncontrolling interest comprised the 20% of EEI not owned by Genco. This noncontrolling interest was classified as a component of equity separate from Genco's equity in its consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren and Genco for the three and six months ended June 30, 2011, and 2010, is shown below:

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:

         

Noncontrolling interest, beginning of period

    $ 155      $ 206      $   154      $   204   

Net income attributable to noncontrolling interest

      1        3        4        7   

Dividends paid to noncontrolling interest holders

      (1 )      (3 )      (3 )      (5 ) 

Noncontrolling interest, end of period

    $ 155      $ 206      $ 155      $ 206   

Genco:

         

Noncontrolling interest, beginning of period

    $ 12      $ 10      $ 11      $ 9   

Net income attributable to noncontrolling interest

      -        1        1        2   

Noncontrolling interest, end of period

    $ 12      $ 11      $ 12      $ 11   

Genco Asset Sale

In June 2011, Genco completed the sale of its remaining interest in the Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $45 million from the sale. Genco recognized an $8 million pretax gain during the second quarter of 2011 relating to this sale. Effective with the sale, the power purchase agreements between Marketing Company and the city of Columbia were terminated.

Summary of Significant Accounting Policies 

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren's primary assets are the common stock of its subsidiaries. Ameren's subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren's principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

 

•  

Ameren Missouri, or Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

 

•  

Ameren Illinois, or Ameren Illinois Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

 

•  

Resources Company, or Ameren Energy Resources Company, LLC, consists of non-rate-regulated operations, including Ameren Energy Generating Company (Genco), AmerenEnergy Resources Generating Company (AERG), Ameren Energy Marketing Company (Marketing Company) and AmerenEnergy Medina Valley Cogen, LLC (Medina Valley). Genco operates a merchant electric generation business in Illinois. Genco has an 80% ownership interest in EEI.

Ameren has various other subsidiaries responsible for activities such as the provision of other shared services.

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The Ameren Illinois Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren's historical cost basis in Ameren Illinois included purchase accounting adjustments related to Ameren's acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distribution as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG's carrying value. Ameren Illinois has segregated AERG's operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. For Ameren's financial statements, AERG's results of operations remain classified as continuing operations. See Note 14 - Discontinued Operations for additional information.

The financial statements of Ameren, Ameren Illinois and Genco are prepared on a consolidated basis. Ameren Missouri has no subsidiaries, and therefore its financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that impacted Genco's year ended December 31, 2010, and three months ended March 31, 2011, consolidated statements of cash flows. For the year ended December 31, 2010, Genco's reported cash flows provided by operating activities were $280 million and cash flows used in financing activities were $251 million. As corrected, Genco's cash flows provided by operating activities were $304 million and cash flows used in financing activities were $275 million. For the three months ended March 31, 2011, Genco's reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected, Genco's cash flows provided by operating activities were $76 million and cash flows provided by financing activities were $24 million. The error was corrected in Genco's six months ended June 30, 2011, consolidated statement of cash flows, included herein. This correction had no impact on Ameren's previously reported consolidated statement of cash flows.

Earnings Per Share

There were no material differences between Ameren's basic and diluted earnings per share amounts for the three months and six months ended June 30, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of June 30, 2011, and changes during the six months ended June 30, 2011, under the Long-term Incentive Plan of 1998, as amended (1998 Plan), and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units(a)      Restricted Shares(b)  
      Share
Units		    

Weighted-average
Fair Value Per Unit

at Grant Date

      Shares    

Weighted-average
Fair Value Per Share

at Grant Date

  

Nonvested at January 1, 2011

      1,142,768      $ 23.96         83,154      $ 49.87   

Granted(c)

      731,962        31.41         -        -   

Dividends

      -        -         518        28.48   

Forfeitures

      (10,261 )      26.14         (560 )      50.45   

Vested(d)

      (131,343 )      30.67         (63,574 )      49.47   

Nonvested at June 30, 2011

      1,733,126      $ 26.58         19,538      $ 51.21   

 

(a) Granted under the 2006 Plan.
(b) Granted under the 1998 Plan.
(c) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2011 under the 2006 Plan.
(d) Shares/units vested due to Ameren attainment of performance goals and 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 January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren's closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $4 million and $2 million for the three months ended June 30, 2011, and 2010, respectively, and a related tax benefit of $2 million and $1 million for the three months ended June 30, 2011, and 2010, respectively. Ameren recorded compensation expense of $7 million for each of the six-month periods ended June 30, 2011, and 2010, respectively, and a related tax benefit of $3 million for each of the six-month periods ended June 30, 2011, and 2010, respectively. As of June 30, 2011, total compensation expense of $27 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 22 months.

Accounting Changes

Disclosures about Fair Value Measurements

See Note 7 - Fair Value Measurements for recently adopted guidance on fair value measurements.

In May 2011, FASB issued authoritative guidance regarding fair value measurements. The guidance amends the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments will not impact the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

 

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance with respect to comprehensive income will not impact the Ameren Companies' results of operations, financial positions, or liquidity or the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amended guidance will only change the presentation of comprehensive income in the financial statements. The new accounting guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of June 30, 2011, Ameren's and Ameren Illinois' goodwill related to the acquisition of IP in 2004 and the acquisition of CILCORP in 2003. We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Intangible Assets. Ameren, Ameren Missouri and Genco classify emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

In July 2011, the EPA issued the CSAPR, which will create new allowances for SO2 and NOx emissions, thereby restricting the use of existing SO2 and NOx allowances to the acid rain program and NOx budget trading program, respectively. In anticipation of the CSAPR announcement, observable market prices for existing emission allowances declined materially. Consequently, during the second quarter of 2011, Ameren and Genco recorded a noncash pretax impairment charge to other operations and maintenance expense of $2 million and $1 million, respectively. Ameren Missouri recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowances, which had no impact to earnings. See Note 9 - Commitments and Contingencies for additional information on emission allowances and the CSAPR.

Emission allowances are charged to fuel expense as they are used in operations. The following table presents amortization expense based on usage of emission allowances, net of gains from emission allowance sales for Ameren, Ameren Missouri and Genco during the three and six months ended June 30, 2011, and 2010. The table below does not include the intangible asset impairment charges referenced above.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren(a)

    $ 1      $ 7      $ 2      $ 10   

AMO

      -        (b )      -        (b ) 

Genco(a)

      1        5        2        8   

AERG(a)

      (b )      2        (b )      2   

 

(a) Includes allowances consumed that were recorded through purchase accounting.
(b) Less than $1 million.

At June 30, 2011, Ameren's and Ameren Missouri's intangible assets also included renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits as of June 30, 2011, was $3 million.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and natural gas customer bills and Ameren Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three and six months ended June 30, 2011 and 2010:

 

      Three Months      Six Months  
      2011      2010      2011      2010  

Ameren

    $ 44       $ 44       $ 95       $ 90   

AMO

      34         33         63         58   

AIC

      10         11         32         32   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2011, was $198 million, $146 million, $33 million, and $16 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2011, that would impact the effective tax rate, if recognized, was $2 million, $2 million, $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

In the second quarter of 2011, final settlement for the 2005 and 2006 years was reached with the Internal Revenue Service, which resulted in the reduction of uncertain tax liabilities by $39 million, $17 million, $12 million and $4 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. Ameren's federal income tax returns for the years 2007 through 2009 are before the Appeals Office of the Internal Revenue Service.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their results of operations, financial position or liquidity.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, Ameren Illinois and Genco increased compared to December 31, 2010, to reflect the accretion of obligations to their fair values.

Noncontrolling Interests

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity in its consolidated balance sheet. Genco's noncontrolling interest comprised the 20% of EEI not owned by Genco. This noncontrolling interest was classified as a component of equity separate from Genco's equity in its consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren and Genco for the three and six months ended June 30, 2011, and 2010, is shown below:

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:

         

Noncontrolling interest, beginning of period

    $ 155      $ 206      $   154      $   204   

Net income attributable to noncontrolling interest

      1        3        4        7   

Dividends paid to noncontrolling interest holders

      (1 )      (3 )      (3 )      (5 ) 

Noncontrolling interest, end of period

    $ 155      $ 206      $ 155      $ 206   

Genco:

         

Noncontrolling interest, beginning of period

    $ 12      $ 10      $ 11      $ 9   

Net income attributable to noncontrolling interest

      -        1        1        2   

Noncontrolling interest, end of period

    $ 12      $ 11      $ 12      $ 11   

Genco Asset Sale

In June 2011, Genco completed the sale of its remaining interest in the Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $45 million from the sale. Genco recognized an $8 million pretax gain during the second quarter of 2011 relating to this sale. Effective with the sale, the power purchase agreements between Marketing Company and the city of Columbia were terminated.

Summary of Significant Accounting Policies 

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren's primary assets are the common stock of its subsidiaries. Ameren's subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses in Missouri and Illinois. Dividends on Ameren's common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren's principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.

 

•  

Ameren Missouri, or Union Electric Company, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri.

 

•  

Ameren Illinois, or Ameren Illinois Company, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

 

•  

Resources Company, or Ameren Energy Resources Company, LLC, consists of non-rate-regulated operations, including Ameren Energy Generating Company (Genco), AmerenEnergy Resources Generating Company (AERG), Ameren Energy Marketing Company (Marketing Company) and AmerenEnergy Medina Valley Cogen, LLC (Medina Valley). Genco operates a merchant electric generation business in Illinois. Genco has an 80% ownership interest in EEI.

Ameren has various other subsidiaries responsible for activities such as the provision of other shared services.

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The Ameren Illinois Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren's historical cost basis in Ameren Illinois included purchase accounting adjustments related to Ameren's acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distribution as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG's carrying value. Ameren Illinois has segregated AERG's operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. For Ameren's financial statements, AERG's results of operations remain classified as continuing operations. See Note 14 - Discontinued Operations for additional information.

The financial statements of Ameren, Ameren Illinois and Genco are prepared on a consolidated basis. Ameren Missouri has no subsidiaries, and therefore its financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that impacted Genco's year ended December 31, 2010, and three months ended March 31, 2011, consolidated statements of cash flows. For the year ended December 31, 2010, Genco's reported cash flows provided by operating activities were $280 million and cash flows used in financing activities were $251 million. As corrected, Genco's cash flows provided by operating activities were $304 million and cash flows used in financing activities were $275 million. For the three months ended March 31, 2011, Genco's reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected, Genco's cash flows provided by operating activities were $76 million and cash flows provided by financing activities were $24 million. The error was corrected in Genco's six months ended June 30, 2011, consolidated statement of cash flows, included herein. This correction had no impact on Ameren's previously reported consolidated statement of cash flows.

Earnings Per Share

There were no material differences between Ameren's basic and diluted earnings per share amounts for the three months and six months ended June 30, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of June 30, 2011, and changes during the six months ended June 30, 2011, under the Long-term Incentive Plan of 1998, as amended (1998 Plan), and the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units(a)      Restricted Shares(b)  
      Share
Units		    

Weighted-average
Fair Value Per Unit

at Grant Date

      Shares    

Weighted-average
Fair Value Per Share

at Grant Date

  

Nonvested at January 1, 2011

      1,142,768      $ 23.96         83,154      $ 49.87   

Granted(c)

      731,962        31.41         -        -   

Dividends

      -        -         518        28.48   

Forfeitures

      (10,261 )      26.14         (560 )      50.45   

Vested(d)

      (131,343 )      30.67         (63,574 )      49.47   

Nonvested at June 30, 2011

      1,733,126      $ 26.58         19,538      $ 51.21   

 

(a) Granted under the 2006 Plan.
(b) Granted under the 1998 Plan.
(c) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2011 under the 2006 Plan.
(d) Shares/units vested due to Ameren attainment of performance goals and 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 January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren's closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $4 million and $2 million for the three months ended June 30, 2011, and 2010, respectively, and a related tax benefit of $2 million and $1 million for the three months ended June 30, 2011, and 2010, respectively. Ameren recorded compensation expense of $7 million for each of the six-month periods ended June 30, 2011, and 2010, respectively, and a related tax benefit of $3 million for each of the six-month periods ended June 30, 2011, and 2010, respectively. As of June 30, 2011, total compensation expense of $27 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 22 months.

Accounting Changes

Disclosures about Fair Value Measurements

See Note 7 - Fair Value Measurements for recently adopted guidance on fair value measurements.

In May 2011, FASB issued authoritative guidance regarding fair value measurements. The guidance amends the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments will not impact the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

 

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance with respect to comprehensive income will not impact the Ameren Companies' results of operations, financial positions, or liquidity or the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amended guidance will only change the presentation of comprehensive income in the financial statements. The new accounting guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of June 30, 2011, Ameren's and Ameren Illinois' goodwill related to the acquisition of IP in 2004 and the acquisition of CILCORP in 2003. We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Intangible Assets. Ameren, Ameren Missouri and Genco classify emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

In July 2011, the EPA issued the CSAPR, which will create new allowances for SO2 and NOx emissions, thereby restricting the use of existing SO2 and NOx allowances to the acid rain program and NOx budget trading program, respectively. In anticipation of the CSAPR announcement, observable market prices for existing emission allowances declined materially. Consequently, during the second quarter of 2011, Ameren and Genco recorded a noncash pretax impairment charge to other operations and maintenance expense of $2 million and $1 million, respectively. Ameren Missouri recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowances, which had no impact to earnings. See Note 9 - Commitments and Contingencies for additional information on emission allowances and the CSAPR.

Emission allowances are charged to fuel expense as they are used in operations. The following table presents amortization expense based on usage of emission allowances, net of gains from emission allowance sales for Ameren, Ameren Missouri and Genco during the three and six months ended June 30, 2011, and 2010. The table below does not include the intangible asset impairment charges referenced above.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren(a)

    $ 1      $ 7      $ 2      $ 10   

AMO

      -        (b )      -        (b ) 

Genco(a)

      1        5        2        8   

AERG(a)

      (b )      2        (b )      2   

 

(a) Includes allowances consumed that were recorded through purchase accounting.
(b) Less than $1 million.

At June 30, 2011, Ameren's and Ameren Missouri's intangible assets also included renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits as of June 30, 2011, was $3 million.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and natural gas customer bills and Ameren Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three and six months ended June 30, 2011 and 2010:

 

      Three Months      Six Months  
      2011      2010      2011      2010  

Ameren

    $ 44       $ 44       $ 95       $ 90   

AMO

      34         33         63         58   

AIC

      10         11         32         32   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2011, was $198 million, $146 million, $33 million, and $16 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2011, that would impact the effective tax rate, if recognized, was $2 million, $2 million, $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

In the second quarter of 2011, final settlement for the 2005 and 2006 years was reached with the Internal Revenue Service, which resulted in the reduction of uncertain tax liabilities by $39 million, $17 million, $12 million and $4 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. Ameren's federal income tax returns for the years 2007 through 2009 are before the Appeals Office of the Internal Revenue Service.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their results of operations, financial position or liquidity.

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, Ameren Illinois and Genco increased compared to December 31, 2010, to reflect the accretion of obligations to their fair values.

Noncontrolling Interests

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity in its consolidated balance sheet. Genco's noncontrolling interest comprised the 20% of EEI not owned by Genco. This noncontrolling interest was classified as a component of equity separate from Genco's equity in its consolidated balance sheet.

A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren and Genco for the three and six months ended June 30, 2011, and 2010, is shown below:

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:

         

Noncontrolling interest, beginning of period

    $ 155      $ 206      $   154      $   204   

Net income attributable to noncontrolling interest

      1        3        4        7   

Dividends paid to noncontrolling interest holders

      (1 )      (3 )      (3 )      (5 ) 

Noncontrolling interest, end of period

    $ 155      $ 206      $ 155      $ 206   

Genco:

         

Noncontrolling interest, beginning of period

    $ 12      $ 10      $ 11      $ 9   

Net income attributable to noncontrolling interest

      -        1        1        2   

Noncontrolling interest, end of period

    $ 12      $ 11      $ 12      $ 11   

Genco Asset Sale

In June 2011, Genco completed the sale of its remaining interest in the Columbia CT facility to the city of Columbia, Missouri. Genco received cash proceeds of $45 million from the sale. Genco recognized an $8 million pretax gain during the second quarter of 2011 relating to this sale. Effective with the sale, the power purchase agreements between Marketing Company and the city of Columbia were terminated.

Rate and Regulatory Matters
6 Months Ended
Jun. 30, 2011
Rate and Regulatory Matters
Text Block 
Ameren Illinois [Member]
 
Rate and Regulatory Matters
Text Block 
Union Electric Company [Member]
 
Rate and Regulatory Matters
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Rate and Regulatory Matters 

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In January 2009, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda, Ameren Missouri's largest electric customer, and the MoOPC appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Cole County Circuit Court. The Stoddard and Pemiscot County cases were consolidated (collectively, the Stoddard Circuit Court), and the Cole County case was dismissed. In September 2009, the Stoddard Circuit Court granted Noranda's request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda's electric service account until the court renders its decision on the appeal. From the granting of the stay request until June 2010, Noranda paid into the Stoddard Circuit Court's registry the entire amount of its monthly base rate increase and monthly FAC payments. In June 2010, when the May 2010 electric rate order became effective, Noranda ceased making base rate payments into the Stoddard Circuit Court's registry. Noranda continued to pay into the Stoddard Circuit Court's registry its monthly FAC payments that related to electric service received during the time periods prior to the effectiveness of the May 2010 electric rate order. Because of the lag between accumulations of changes in net fuel costs and when those net fuel costs are recovered through FAC charges applied to customers' bills, a portion of Noranda's FAC payment in January 2012 is expected to be the last contested amount deposited into the Stoddard Circuit Court's registry relating to this 2009 electric rate order appeal. As of June 30, 2011, the aggregate amount held in the Stoddard Circuit Court's registry was $16 million.

In August 2010, the Stoddard Circuit Court issued a judgment that reversed parts of the MoPSC's decision. Also, upon issuance, the Stoddard Circuit Court suspended its own judgment. Therefore, the entire amount held in the Stoddard Circuit Court's registry will remain in the Stoddard Circuit Court's registry pending the appeal discussed below.

In September 2010, Ameren Missouri filed an appeal with the Missouri Court of Appeals, Southern District. The Missouri Court of Appeals will conduct an independent review of the MoPSC's order. Ameren Missouri believes the Stoddard Circuit Court's judgment, which reversed parts of the MoPSC decision, will be found erroneous by the Court of Appeals; however, there can be no assurances that Ameren Missouri's appeal will be successful. If Ameren Missouri prevails on all issues of its appeal, Ameren Missouri will receive all of the funds held in the Stoddard Circuit Court's registry, plus accrued interest. A decision by the Missouri Court of Appeals is expected in 2011.

2010 Electric Rate Order

In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside Ameren Missouri's system.

The MIEC and MoOPC appealed certain aspects of the MoPSC order to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also filed a request for a stay with the Cole County Circuit Court. In December 2010, the Cole County Circuit Court granted the request of the four industrial customers to stay the MoPSC's 2010 electric rate order and required those customers to pay into the Cole County Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under a Missouri electric rate order that became effective in June 2007, the last Ameren Missouri rate order for which appeals have been exhausted. On February 15, 2011, the four industrial customers posted the bond required by the stay. Since the bond was posted, the four industrial customers have made payments into the Cole County Circuit Court's registry equal to the difference between their billings under 2010 electric rates, which includes the FAC, and 2007 electric rates. As of June 30, 2011, the aggregate amount held by the Cole County Circuit Court, excluding the bond amount, was $8 million.

On February 16, 2011, the MoOPC and the MIEC separately made filings with the MoPSC in which each argued that the stay granted by the Cole County Circuit Court in December 2010 should apply to all Ameren Missouri customers rather than to just the four industrial customers that requested the stay. The MoOPC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The MIEC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order), including the FAC, and replace them with Ameren Missouri's rate schedules approved by the MoPSC in its 2007 electric rate order for all customers. On March 16, 2011, the MoPSC denied the MoOPC's request to suspend Ameren Missouri's currently effective rate schedules for all customers. By denying the MoOPC's request, the MoPSC effectively denied the MIEC's request to suspend currently effective rate schedules as well. The MoOPC and the MIEC then asked the Missouri Court of Appeals, Western District, to require the MoPSC to suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The Missouri Court of Appeals denied the request. On March 28, 2011, the MoOPC and MIEC made the same request to apply the stay granted to four industrial customers to all Ameren Missouri electric customers to the Cole County Circuit Court. On April 12, 2011, the Cole County Circuit Court denied the motion filed by the MoOPC and MIEC. The Cole County Circuit Court's April 12, 2011 order concluded that the stay only granted the request of the four industrial customers to pay into the Cole County Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under the 2007 Missouri electric rate order; and that the language in the stay on which the March 28, 2011 motion by the MIEC and MoOPC was based was not part of the operative language of the stay and therefore the stay did not require Ameren Missouri to cease charging the rates approved by the 2010 Missouri electric rate order to all Ameren Missouri electric customers.

 

With respect to further judicial proceedings regarding the 2010 electric rate order, Ameren Missouri will continue to address the merits of the order and any further filings that might be made relating to the stay, if any, through the judicial and regulatory review processes. We cannot predict the ultimate outcome of these proceedings, which could have a material effect on Ameren Missouri's and Ameren's results of operations, financial position, and liquidity.

The stay in effect for the four industrial customers does not address the merits of the appeals of the MoPSC's 2010 electric rate order or the 2009 electric rate order, which will be addressed in the ordinary course of the judicial review process. At this time, Ameren Missouri does not believe any aspect of the 2009 and 2010 electric rate increases authorized by the 2009 and 2010 MoPSC electric rate orders are probable of refund to Ameren Missouri's customers. If Ameren Missouri were to conclude that some portion of these rate increases becomes probable of refund to Ameren Missouri's customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that determination was made. A decision is expected to be issued on the MIEC's and MoOPC's appeal by the Cole County Circuit Court in 2011.

2011 Electric Rate Order

On July 13, 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $173 million, including $52 million related to an increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. The revenue increase was based on a 10.2% return on equity, a capital structure composed of 52.2% common equity, and a rate base of approximately $6.6 billion. The rate changes became effective on July 31, 2011. The MoPSC order approved the continued use of Ameren Missouri's vegetation management and infrastructure cost tracker, pension and postretirement benefit cost tracker, and FAC at the current 95% sharing level. The MoPSC order shortened the FAC recovery and refund period from 12 months to 8 months. The MoPSC order denied Ameren Missouri's request for the ability to recover any under-recovery of fixed costs as a result of lower sales volumes from the implementation of energy efficiency measures.

Additionally, the MoPSC order provided for a tracking mechanism for uncertain income tax positions. The order provides that reserves for uncertain tax positions do not reduce rate base. However, when an uncertain tax position liability is resolved, the order requires the creation of a regulatory asset or regulatory liability to reflect the time value (using the weighted average cost of capital in the order) of the difference between the uncertain tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will be amortized over three years beginning on the effective date of the next electric rate case.

The 2011 electric rate order also allowed for the full recovery of investments for the Sioux energy center scrubbers and related 2011 property taxes for the Sioux and Taum Sauk energy centers. However, the MoPSC order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result of the order, Ameren and Ameren Missouri will each record a pretax charge to earnings of $89 million, relating to the Taum Sauk disallowance, in the third quarter ending September 30, 2011.

Further, the MoPSC order adjusted or established the recovery period of multiple regulatory assets and regulatory liabilities. The following table summarizes the changes to the recovery period of regulatory assets and regulatory liabilities as directed in the MoPSC's July 2011 rate order. The recovery periods became effective on August 1, 2011.

 

Regulatory Assets and Liabilities   

Regulatory Asset

(Liability) Balance
at June 30, 2011

    

Recovery Period

Ends

  

Demand-side costs(a)

    $ 33        July 2017   

Construction accounting for pollution control equipment(a)

      25        July 2038   

SO2 emissions allowances sales tracker(b)

      8        July 2013   

FERC-ordered MISO resettlements(b)

      2        July 2013   

2006 Storm costs(b)

      1        July 2013   

Vegetation management and infrastructure inspection(b)

      (3 )      July 2013   

Pension and postretirement benefit cost tracker for 2010 costs(a)

      (11 )      July 2016   

Total

    $ 55           

 

(a) Recovery period first established in the MoPSC's July 2011 rate order.
(b) Previous recovery period was extended.

On July 1, 2011, a new law took effect that reformed the judicial appeal process of MoPSC rate orders. Among other items, the new law allows appeals to be made directly to the appellate court, bypassing the circuit court. The new law provides that rates cannot be stayed; however, the Appellate Court could direct the MoPSC to revise the rates based on its appeal ruling. Such rate revisions could be ordered to be applied retroactively. The provisions of this new law will apply to any judicial appeals of the MoPSC's July 2011 rate order.

In July 2011, Ameren Missouri and other parties to the rate case filed for rehearing of various aspects of the order including the disallowance of Taum Sauk enhancements. The MoPSC rejected the requests. Subsequently, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. Ameren Missouri cannot predict the ultimate outcome of its appeal.

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of Ameren Missouri's FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its prudence review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri due to the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in the second quarter of 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009.

Ameren Missouri disagrees with the MoPSC order's classification of these sales and believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. In May 2011, Ameren Missouri filed a rehearing request with the MoPSC, which was denied. In June 2011, Ameren Missouri filed an appeal with the Cole County Circuit Court. A decision is expected from the Cole County Circuit Court in 2011. Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. We cannot predict the ultimate outcome of these regulatory or judicial proceedings.

Ameren Missouri recognized an additional $25 million of pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC has not completed a prudence review of the FAC for this subsequent period. Consequently, the MoPSC order issued in April 2011 did not address any pretax earnings associated with the same long-term partial requirements contracts subsequent to September 30, 2009. The next prudence review is scheduled to be initiated in September 2011. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

In February 2011, Ameren Illinois filed a request with the ICC to increase its annual revenues for electric delivery service. The currently pending request, as revised in July 2011, seeks to increase annual revenues for electric delivery service by $40 million. The revised electric rate increase request was based on an 11.0% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $2 billion.

In July 2011, Ameren Illinois also revised its February 2011 request with the ICC to increase its annual revenues for natural gas delivery service. The currently pending request seeks to increase annual revenues for natural gas delivery service by $50 million. The revised natural gas rate increase request was based on a 10.75% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $957 million.

In an attempt to limit regulatory lag, Ameren Illinois used a future test year, 2012, in each of these rate requests. In its July 2011 revision, Ameren Illinois withdrew its request for a rider mechanism for its pension costs.

In June 2011, the ICC staff responded to Ameren Illinois' original filed requests. The ICC staff recommended a net decrease in revenues for electric delivery service of $10 million, based on a 9.72% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $2 billion. The ICC staff recommended a net increase in revenues for natural gas delivery service of $16 million, based on an 8.9% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $942 million. Other parties also made recommendations through testimony filed in the electric and natural gas delivery service rate cases.

 

A decision by the ICC in these proceedings is required by January 2012. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve or whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect.

Federal

Electric Transmission Investment

FERC, in its order issued in May 2011, approved transmission rate incentives for ATX, Ameren Missouri and Ameren Illinois for two new transmission projects. These initial projects, subject to MISO approval, consist of a potential $1 billion investment in high voltage transmission projects in Illinois and Missouri. The FERC order approved the following rate mechanisms with respect to ATX's initial portfolio of transmission projects:

 

•  

Full recovery of financing costs associated with construction work in progress before the asset is placed in service;

 

•  

Recovery of prudently incurred costs in developing project facilities that might later be abandoned due to issues outside the company's control;

 

•  

Use of a hypothetical capital structure reflecting the capital structure of Ameren Illinois as of December 31, 2009, which would afford ATX a capital structure that resembles that of a utility company; and

 

•  

Permission to allow ATX to recover operating and maintenance costs incurred in the early development stages of the projects.

COLA and ESP

In 2008, Ameren Missouri filed an application with the NRC for a COLA for a new 1,600-megawatt nuclear unit at Ameren Missouri's existing Callaway County, Missouri, nuclear 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 COLA.

Ameren Missouri is considering filing an application to obtain an ESP from the NRC for the Callaway energy center site. An ESP approves a specific location for a nuclear facility; however, additional licenses would be required for the specific type and design of nuclear facility to be built at that site. An ESP does not authorize construction of a plant. An ESP is valid for 20 years and potentially could be renewed for up to an additional 20 years. Attempts to pass legislation to maintain an option for nuclear power in the state of Missouri by recovering the costs of the ESP, subject to appropriate consumer protections, were not successful during the 2011 spring Missouri legislative session. However, support for nuclear power exists in the state of Missouri, which could lead to the passage of an ESP recovery mechanism in future legislative sessions. Ameren Missouri's pursuit of an ESP is dependent upon enactment of a legislative framework ensuring cost recovery.

As of June 30, 2011, Ameren Missouri had capitalized approximately $67 million relating to its efforts to construct a new nuclear unit. All of these incurred costs will remain capitalized while management assesses options to maximize the value of its investment in this project. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.

Rate and Regulatory Matters 

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In January 2009, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda, Ameren Missouri's largest electric customer, and the MoOPC appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Cole County Circuit Court. The Stoddard and Pemiscot County cases were consolidated (collectively, the Stoddard Circuit Court), and the Cole County case was dismissed. In September 2009, the Stoddard Circuit Court granted Noranda's request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda's electric service account until the court renders its decision on the appeal. From the granting of the stay request until June 2010, Noranda paid into the Stoddard Circuit Court's registry the entire amount of its monthly base rate increase and monthly FAC payments. In June 2010, when the May 2010 electric rate order became effective, Noranda ceased making base rate payments into the Stoddard Circuit Court's registry. Noranda continued to pay into the Stoddard Circuit Court's registry its monthly FAC payments that related to electric service received during the time periods prior to the effectiveness of the May 2010 electric rate order. Because of the lag between accumulations of changes in net fuel costs and when those net fuel costs are recovered through FAC charges applied to customers' bills, a portion of Noranda's FAC payment in January 2012 is expected to be the last contested amount deposited into the Stoddard Circuit Court's registry relating to this 2009 electric rate order appeal. As of June 30, 2011, the aggregate amount held in the Stoddard Circuit Court's registry was $16 million.

In August 2010, the Stoddard Circuit Court issued a judgment that reversed parts of the MoPSC's decision. Also, upon issuance, the Stoddard Circuit Court suspended its own judgment. Therefore, the entire amount held in the Stoddard Circuit Court's registry will remain in the Stoddard Circuit Court's registry pending the appeal discussed below.

In September 2010, Ameren Missouri filed an appeal with the Missouri Court of Appeals, Southern District. The Missouri Court of Appeals will conduct an independent review of the MoPSC's order. Ameren Missouri believes the Stoddard Circuit Court's judgment, which reversed parts of the MoPSC decision, will be found erroneous by the Court of Appeals; however, there can be no assurances that Ameren Missouri's appeal will be successful. If Ameren Missouri prevails on all issues of its appeal, Ameren Missouri will receive all of the funds held in the Stoddard Circuit Court's registry, plus accrued interest. A decision by the Missouri Court of Appeals is expected in 2011.

2010 Electric Rate Order

In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside Ameren Missouri's system.

The MIEC and MoOPC appealed certain aspects of the MoPSC order to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also filed a request for a stay with the Cole County Circuit Court. In December 2010, the Cole County Circuit Court granted the request of the four industrial customers to stay the MoPSC's 2010 electric rate order and required those customers to pay into the Cole County Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under a Missouri electric rate order that became effective in June 2007, the last Ameren Missouri rate order for which appeals have been exhausted. On February 15, 2011, the four industrial customers posted the bond required by the stay. Since the bond was posted, the four industrial customers have made payments into the Cole County Circuit Court's registry equal to the difference between their billings under 2010 electric rates, which includes the FAC, and 2007 electric rates. As of June 30, 2011, the aggregate amount held by the Cole County Circuit Court, excluding the bond amount, was $8 million.

On February 16, 2011, the MoOPC and the MIEC separately made filings with the MoPSC in which each argued that the stay granted by the Cole County Circuit Court in December 2010 should apply to all Ameren Missouri customers rather than to just the four industrial customers that requested the stay. The MoOPC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The MIEC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order), including the FAC, and replace them with Ameren Missouri's rate schedules approved by the MoPSC in its 2007 electric rate order for all customers. On March 16, 2011, the MoPSC denied the MoOPC's request to suspend Ameren Missouri's currently effective rate schedules for all customers. By denying the MoOPC's request, the MoPSC effectively denied the MIEC's request to suspend currently effective rate schedules as well. The MoOPC and the MIEC then asked the Missouri Court of Appeals, Western District, to require the MoPSC to suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The Missouri Court of Appeals denied the request. On March 28, 2011, the MoOPC and MIEC made the same request to apply the stay granted to four industrial customers to all Ameren Missouri electric customers to the Cole County Circuit Court. On April 12, 2011, the Cole County Circuit Court denied the motion filed by the MoOPC and MIEC. The Cole County Circuit Court's April 12, 2011 order concluded that the stay only granted the request of the four industrial customers to pay into the Cole County Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under the 2007 Missouri electric rate order; and that the language in the stay on which the March 28, 2011 motion by the MIEC and MoOPC was based was not part of the operative language of the stay and therefore the stay did not require Ameren Missouri to cease charging the rates approved by the 2010 Missouri electric rate order to all Ameren Missouri electric customers.

 

With respect to further judicial proceedings regarding the 2010 electric rate order, Ameren Missouri will continue to address the merits of the order and any further filings that might be made relating to the stay, if any, through the judicial and regulatory review processes. We cannot predict the ultimate outcome of these proceedings, which could have a material effect on Ameren Missouri's and Ameren's results of operations, financial position, and liquidity.

The stay in effect for the four industrial customers does not address the merits of the appeals of the MoPSC's 2010 electric rate order or the 2009 electric rate order, which will be addressed in the ordinary course of the judicial review process. At this time, Ameren Missouri does not believe any aspect of the 2009 and 2010 electric rate increases authorized by the 2009 and 2010 MoPSC electric rate orders are probable of refund to Ameren Missouri's customers. If Ameren Missouri were to conclude that some portion of these rate increases becomes probable of refund to Ameren Missouri's customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that determination was made. A decision is expected to be issued on the MIEC's and MoOPC's appeal by the Cole County Circuit Court in 2011.

2011 Electric Rate Order

On July 13, 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $173 million, including $52 million related to an increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. The revenue increase was based on a 10.2% return on equity, a capital structure composed of 52.2% common equity, and a rate base of approximately $6.6 billion. The rate changes became effective on July 31, 2011. The MoPSC order approved the continued use of Ameren Missouri's vegetation management and infrastructure cost tracker, pension and postretirement benefit cost tracker, and FAC at the current 95% sharing level. The MoPSC order shortened the FAC recovery and refund period from 12 months to 8 months. The MoPSC order denied Ameren Missouri's request for the ability to recover any under-recovery of fixed costs as a result of lower sales volumes from the implementation of energy efficiency measures.

Additionally, the MoPSC order provided for a tracking mechanism for uncertain income tax positions. The order provides that reserves for uncertain tax positions do not reduce rate base. However, when an uncertain tax position liability is resolved, the order requires the creation of a regulatory asset or regulatory liability to reflect the time value (using the weighted average cost of capital in the order) of the difference between the uncertain tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will be amortized over three years beginning on the effective date of the next electric rate case.

The 2011 electric rate order also allowed for the full recovery of investments for the Sioux energy center scrubbers and related 2011 property taxes for the Sioux and Taum Sauk energy centers. However, the MoPSC order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result of the order, Ameren and Ameren Missouri will each record a pretax charge to earnings of $89 million, relating to the Taum Sauk disallowance, in the third quarter ending September 30, 2011.

Further, the MoPSC order adjusted or established the recovery period of multiple regulatory assets and regulatory liabilities. The following table summarizes the changes to the recovery period of regulatory assets and regulatory liabilities as directed in the MoPSC's July 2011 rate order. The recovery periods became effective on August 1, 2011.

 

Regulatory Assets and Liabilities   

Regulatory Asset

(Liability) Balance
at June 30, 2011

    

Recovery Period

Ends

  

Demand-side costs(a)

    $ 33        July 2017   

Construction accounting for pollution control equipment(a)

      25        July 2038   

SO2 emissions allowances sales tracker(b)

      8        July 2013   

FERC-ordered MISO resettlements(b)

      2        July 2013   

2006 Storm costs(b)

      1        July 2013   

Vegetation management and infrastructure inspection(b)

      (3 )      July 2013   

Pension and postretirement benefit cost tracker for 2010 costs(a)

      (11 )      July 2016   

Total

    $ 55           

 

(a) Recovery period first established in the MoPSC's July 2011 rate order.
(b) Previous recovery period was extended.

On July 1, 2011, a new law took effect that reformed the judicial appeal process of MoPSC rate orders. Among other items, the new law allows appeals to be made directly to the appellate court, bypassing the circuit court. The new law provides that rates cannot be stayed; however, the Appellate Court could direct the MoPSC to revise the rates based on its appeal ruling. Such rate revisions could be ordered to be applied retroactively. The provisions of this new law will apply to any judicial appeals of the MoPSC's July 2011 rate order.

In July 2011, Ameren Missouri and other parties to the rate case filed for rehearing of various aspects of the order including the disallowance of Taum Sauk enhancements. The MoPSC rejected the requests. Subsequently, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. Ameren Missouri cannot predict the ultimate outcome of its appeal.

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of Ameren Missouri's FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its prudence review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri due to the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in the second quarter of 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009.

Ameren Missouri disagrees with the MoPSC order's classification of these sales and believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. In May 2011, Ameren Missouri filed a rehearing request with the MoPSC, which was denied. In June 2011, Ameren Missouri filed an appeal with the Cole County Circuit Court. A decision is expected from the Cole County Circuit Court in 2011. Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. We cannot predict the ultimate outcome of these regulatory or judicial proceedings.

Ameren Missouri recognized an additional $25 million of pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC has not completed a prudence review of the FAC for this subsequent period. Consequently, the MoPSC order issued in April 2011 did not address any pretax earnings associated with the same long-term partial requirements contracts subsequent to September 30, 2009. The next prudence review is scheduled to be initiated in September 2011. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

In February 2011, Ameren Illinois filed a request with the ICC to increase its annual revenues for electric delivery service. The currently pending request, as revised in July 2011, seeks to increase annual revenues for electric delivery service by $40 million. The revised electric rate increase request was based on an 11.0% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $2 billion.

In July 2011, Ameren Illinois also revised its February 2011 request with the ICC to increase its annual revenues for natural gas delivery service. The currently pending request seeks to increase annual revenues for natural gas delivery service by $50 million. The revised natural gas rate increase request was based on a 10.75% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $957 million.

In an attempt to limit regulatory lag, Ameren Illinois used a future test year, 2012, in each of these rate requests. In its July 2011 revision, Ameren Illinois withdrew its request for a rider mechanism for its pension costs.

In June 2011, the ICC staff responded to Ameren Illinois' original filed requests. The ICC staff recommended a net decrease in revenues for electric delivery service of $10 million, based on a 9.72% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $2 billion. The ICC staff recommended a net increase in revenues for natural gas delivery service of $16 million, based on an 8.9% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $942 million. Other parties also made recommendations through testimony filed in the electric and natural gas delivery service rate cases.

 

A decision by the ICC in these proceedings is required by January 2012. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve or whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect.

Federal

Electric Transmission Investment

FERC, in its order issued in May 2011, approved transmission rate incentives for ATX, Ameren Missouri and Ameren Illinois for two new transmission projects. These initial projects, subject to MISO approval, consist of a potential $1 billion investment in high voltage transmission projects in Illinois and Missouri. The FERC order approved the following rate mechanisms with respect to ATX's initial portfolio of transmission projects:

 

•  

Full recovery of financing costs associated with construction work in progress before the asset is placed in service;

 

•  

Recovery of prudently incurred costs in developing project facilities that might later be abandoned due to issues outside the company's control;

 

•  

Use of a hypothetical capital structure reflecting the capital structure of Ameren Illinois as of December 31, 2009, which would afford ATX a capital structure that resembles that of a utility company; and

 

•  

Permission to allow ATX to recover operating and maintenance costs incurred in the early development stages of the projects.

COLA and ESP

In 2008, Ameren Missouri filed an application with the NRC for a COLA for a new 1,600-megawatt nuclear unit at Ameren Missouri's existing Callaway County, Missouri, nuclear 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 COLA.

Ameren Missouri is considering filing an application to obtain an ESP from the NRC for the Callaway energy center site. An ESP approves a specific location for a nuclear facility; however, additional licenses would be required for the specific type and design of nuclear facility to be built at that site. An ESP does not authorize construction of a plant. An ESP is valid for 20 years and potentially could be renewed for up to an additional 20 years. Attempts to pass legislation to maintain an option for nuclear power in the state of Missouri by recovering the costs of the ESP, subject to appropriate consumer protections, were not successful during the 2011 spring Missouri legislative session. However, support for nuclear power exists in the state of Missouri, which could lead to the passage of an ESP recovery mechanism in future legislative sessions. Ameren Missouri's pursuit of an ESP is dependent upon enactment of a legislative framework ensuring cost recovery.

As of June 30, 2011, Ameren Missouri had capitalized approximately $67 million relating to its efforts to construct a new nuclear unit. All of these incurred costs will remain capitalized while management assesses options to maximize the value of its investment in this project. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.

Rate and Regulatory Matters 

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In January 2009, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues of approximately $162 million for electric service and the implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism, among other things. In February 2009, Noranda, Ameren Missouri's largest electric customer, and the MoOPC appealed certain aspects of the MoPSC decision to the Circuit Court of Pemiscot County, Missouri, the Circuit Court of Stoddard County, Missouri, and the Cole County Circuit Court. The Stoddard and Pemiscot County cases were consolidated (collectively, the Stoddard Circuit Court), and the Cole County case was dismissed. In September 2009, the Stoddard Circuit Court granted Noranda's request to stay the electric rate increase granted by the January 2009 MoPSC order as it applies specifically to Noranda's electric service account until the court renders its decision on the appeal. From the granting of the stay request until June 2010, Noranda paid into the Stoddard Circuit Court's registry the entire amount of its monthly base rate increase and monthly FAC payments. In June 2010, when the May 2010 electric rate order became effective, Noranda ceased making base rate payments into the Stoddard Circuit Court's registry. Noranda continued to pay into the Stoddard Circuit Court's registry its monthly FAC payments that related to electric service received during the time periods prior to the effectiveness of the May 2010 electric rate order. Because of the lag between accumulations of changes in net fuel costs and when those net fuel costs are recovered through FAC charges applied to customers' bills, a portion of Noranda's FAC payment in January 2012 is expected to be the last contested amount deposited into the Stoddard Circuit Court's registry relating to this 2009 electric rate order appeal. As of June 30, 2011, the aggregate amount held in the Stoddard Circuit Court's registry was $16 million.

In August 2010, the Stoddard Circuit Court issued a judgment that reversed parts of the MoPSC's decision. Also, upon issuance, the Stoddard Circuit Court suspended its own judgment. Therefore, the entire amount held in the Stoddard Circuit Court's registry will remain in the Stoddard Circuit Court's registry pending the appeal discussed below.

In September 2010, Ameren Missouri filed an appeal with the Missouri Court of Appeals, Southern District. The Missouri Court of Appeals will conduct an independent review of the MoPSC's order. Ameren Missouri believes the Stoddard Circuit Court's judgment, which reversed parts of the MoPSC decision, will be found erroneous by the Court of Appeals; however, there can be no assurances that Ameren Missouri's appeal will be successful. If Ameren Missouri prevails on all issues of its appeal, Ameren Missouri will receive all of the funds held in the Stoddard Circuit Court's registry, plus accrued interest. A decision by the Missouri Court of Appeals is expected in 2011.

2010 Electric Rate Order

In May 2010, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $230 million, including $119 million to cover higher fuel costs and lower revenue from sales outside Ameren Missouri's system.

The MIEC and MoOPC appealed certain aspects of the MoPSC order to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also filed a request for a stay with the Cole County Circuit Court. In December 2010, the Cole County Circuit Court granted the request of the four industrial customers to stay the MoPSC's 2010 electric rate order and required those customers to pay into the Cole County Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under a Missouri electric rate order that became effective in June 2007, the last Ameren Missouri rate order for which appeals have been exhausted. On February 15, 2011, the four industrial customers posted the bond required by the stay. Since the bond was posted, the four industrial customers have made payments into the Cole County Circuit Court's registry equal to the difference between their billings under 2010 electric rates, which includes the FAC, and 2007 electric rates. As of June 30, 2011, the aggregate amount held by the Cole County Circuit Court, excluding the bond amount, was $8 million.

On February 16, 2011, the MoOPC and the MIEC separately made filings with the MoPSC in which each argued that the stay granted by the Cole County Circuit Court in December 2010 should apply to all Ameren Missouri customers rather than to just the four industrial customers that requested the stay. The MoOPC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The MIEC requested the MoPSC suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order), including the FAC, and replace them with Ameren Missouri's rate schedules approved by the MoPSC in its 2007 electric rate order for all customers. On March 16, 2011, the MoPSC denied the MoOPC's request to suspend Ameren Missouri's currently effective rate schedules for all customers. By denying the MoOPC's request, the MoPSC effectively denied the MIEC's request to suspend currently effective rate schedules as well. The MoOPC and the MIEC then asked the Missouri Court of Appeals, Western District, to require the MoPSC to suspend Ameren Missouri's currently effective rate schedules (approved by the 2010 Missouri electric rate order) and to replace them with Ameren Missouri's previously effective rate schedules (approved by the 2009 Missouri electric rate order) for all customers. The Missouri Court of Appeals denied the request. On March 28, 2011, the MoOPC and MIEC made the same request to apply the stay granted to four industrial customers to all Ameren Missouri electric customers to the Cole County Circuit Court. On April 12, 2011, the Cole County Circuit Court denied the motion filed by the MoOPC and MIEC. The Cole County Circuit Court's April 12, 2011 order concluded that the stay only granted the request of the four industrial customers to pay into the Cole County Circuit Court's registry the difference between their billings under the 2010 Missouri electric rate order and their billings under the 2007 Missouri electric rate order; and that the language in the stay on which the March 28, 2011 motion by the MIEC and MoOPC was based was not part of the operative language of the stay and therefore the stay did not require Ameren Missouri to cease charging the rates approved by the 2010 Missouri electric rate order to all Ameren Missouri electric customers.

 

With respect to further judicial proceedings regarding the 2010 electric rate order, Ameren Missouri will continue to address the merits of the order and any further filings that might be made relating to the stay, if any, through the judicial and regulatory review processes. We cannot predict the ultimate outcome of these proceedings, which could have a material effect on Ameren Missouri's and Ameren's results of operations, financial position, and liquidity.

The stay in effect for the four industrial customers does not address the merits of the appeals of the MoPSC's 2010 electric rate order or the 2009 electric rate order, which will be addressed in the ordinary course of the judicial review process. At this time, Ameren Missouri does not believe any aspect of the 2009 and 2010 electric rate increases authorized by the 2009 and 2010 MoPSC electric rate orders are probable of refund to Ameren Missouri's customers. If Ameren Missouri were to conclude that some portion of these rate increases becomes probable of refund to Ameren Missouri's customers, a charge to earnings would be recorded for the estimated amount of refund in the period in which that determination was made. A decision is expected to be issued on the MIEC's and MoOPC's appeal by the Cole County Circuit Court in 2011.

2011 Electric Rate Order

On July 13, 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of approximately $173 million, including $52 million related to an increase in normalized net fuel costs above the net fuel costs included in base rates previously authorized by the MoPSC in its May 2010 electric rate order. The revenue increase was based on a 10.2% return on equity, a capital structure composed of 52.2% common equity, and a rate base of approximately $6.6 billion. The rate changes became effective on July 31, 2011. The MoPSC order approved the continued use of Ameren Missouri's vegetation management and infrastructure cost tracker, pension and postretirement benefit cost tracker, and FAC at the current 95% sharing level. The MoPSC order shortened the FAC recovery and refund period from 12 months to 8 months. The MoPSC order denied Ameren Missouri's request for the ability to recover any under-recovery of fixed costs as a result of lower sales volumes from the implementation of energy efficiency measures.

Additionally, the MoPSC order provided for a tracking mechanism for uncertain income tax positions. The order provides that reserves for uncertain tax positions do not reduce rate base. However, when an uncertain tax position liability is resolved, the order requires the creation of a regulatory asset or regulatory liability to reflect the time value (using the weighted average cost of capital in the order) of the difference between the uncertain tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will be amortized over three years beginning on the effective date of the next electric rate case.

The 2011 electric rate order also allowed for the full recovery of investments for the Sioux energy center scrubbers and related 2011 property taxes for the Sioux and Taum Sauk energy centers. However, the MoPSC order disallowed the recovery of all costs of enhancements, or costs that would have been incurred absent the breach, related to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance. As a result of the order, Ameren and Ameren Missouri will each record a pretax charge to earnings of $89 million, relating to the Taum Sauk disallowance, in the third quarter ending September 30, 2011.

Further, the MoPSC order adjusted or established the recovery period of multiple regulatory assets and regulatory liabilities. The following table summarizes the changes to the recovery period of regulatory assets and regulatory liabilities as directed in the MoPSC's July 2011 rate order. The recovery periods became effective on August 1, 2011.

 

Regulatory Assets and Liabilities   

Regulatory Asset

(Liability) Balance
at June 30, 2011

    

Recovery Period

Ends

  

Demand-side costs(a)

    $ 33        July 2017   

Construction accounting for pollution control equipment(a)

      25        July 2038   

SO2 emissions allowances sales tracker(b)

      8        July 2013   

FERC-ordered MISO resettlements(b)

      2        July 2013   

2006 Storm costs(b)

      1        July 2013   

Vegetation management and infrastructure inspection(b)

      (3 )      July 2013   

Pension and postretirement benefit cost tracker for 2010 costs(a)

      (11 )      July 2016   

Total

    $ 55           

 

(a) Recovery period first established in the MoPSC's July 2011 rate order.
(b) Previous recovery period was extended.

On July 1, 2011, a new law took effect that reformed the judicial appeal process of MoPSC rate orders. Among other items, the new law allows appeals to be made directly to the appellate court, bypassing the circuit court. The new law provides that rates cannot be stayed; however, the Appellate Court could direct the MoPSC to revise the rates based on its appeal ruling. Such rate revisions could be ordered to be applied retroactively. The provisions of this new law will apply to any judicial appeals of the MoPSC's July 2011 rate order.

In July 2011, Ameren Missouri and other parties to the rate case filed for rehearing of various aspects of the order including the disallowance of Taum Sauk enhancements. The MoPSC rejected the requests. Subsequently, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. Ameren Missouri cannot predict the ultimate outcome of its appeal.

FAC Prudence Review

Missouri law requires the MoPSC to complete prudence reviews of Ameren Missouri's FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its prudence review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri due to the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in the second quarter of 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009.

Ameren Missouri disagrees with the MoPSC order's classification of these sales and believes that the terms of its FAC tariff did not provide for the inclusion of these sales in the FAC calculation. In May 2011, Ameren Missouri filed a rehearing request with the MoPSC, which was denied. In June 2011, Ameren Missouri filed an appeal with the Cole County Circuit Court. A decision is expected from the Cole County Circuit Court in 2011. Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. We cannot predict the ultimate outcome of these regulatory or judicial proceedings.

Ameren Missouri recognized an additional $25 million of pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC has not completed a prudence review of the FAC for this subsequent period. Consequently, the MoPSC order issued in April 2011 did not address any pretax earnings associated with the same long-term partial requirements contracts subsequent to September 30, 2009. The next prudence review is scheduled to be initiated in September 2011. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made.

Illinois

Pending Electric and Natural Gas Delivery Service Rate Cases

In February 2011, Ameren Illinois filed a request with the ICC to increase its annual revenues for electric delivery service. The currently pending request, as revised in July 2011, seeks to increase annual revenues for electric delivery service by $40 million. The revised electric rate increase request was based on an 11.0% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $2 billion.

In July 2011, Ameren Illinois also revised its February 2011 request with the ICC to increase its annual revenues for natural gas delivery service. The currently pending request seeks to increase annual revenues for natural gas delivery service by $50 million. The revised natural gas rate increase request was based on a 10.75% return on equity, a capital structure composed of 52.9% common equity, and a rate base of $957 million.

In an attempt to limit regulatory lag, Ameren Illinois used a future test year, 2012, in each of these rate requests. In its July 2011 revision, Ameren Illinois withdrew its request for a rider mechanism for its pension costs.

In June 2011, the ICC staff responded to Ameren Illinois' original filed requests. The ICC staff recommended a net decrease in revenues for electric delivery service of $10 million, based on a 9.72% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $2 billion. The ICC staff recommended a net increase in revenues for natural gas delivery service of $16 million, based on an 8.9% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $942 million. Other parties also made recommendations through testimony filed in the electric and natural gas delivery service rate cases.

 

A decision by the ICC in these proceedings is required by January 2012. Ameren Illinois cannot predict the level of any delivery service rate changes the ICC may approve or whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect.

Federal

Electric Transmission Investment

FERC, in its order issued in May 2011, approved transmission rate incentives for ATX, Ameren Missouri and Ameren Illinois for two new transmission projects. These initial projects, subject to MISO approval, consist of a potential $1 billion investment in high voltage transmission projects in Illinois and Missouri. The FERC order approved the following rate mechanisms with respect to ATX's initial portfolio of transmission projects:

 

•  

Full recovery of financing costs associated with construction work in progress before the asset is placed in service;

 

•  

Recovery of prudently incurred costs in developing project facilities that might later be abandoned due to issues outside the company's control;

 

•  

Use of a hypothetical capital structure reflecting the capital structure of Ameren Illinois as of December 31, 2009, which would afford ATX a capital structure that resembles that of a utility company; and

 

•  

Permission to allow ATX to recover operating and maintenance costs incurred in the early development stages of the projects.

COLA and ESP

In 2008, Ameren Missouri filed an application with the NRC for a COLA for a new 1,600-megawatt nuclear unit at Ameren Missouri's existing Callaway County, Missouri, nuclear 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 COLA.

Ameren Missouri is considering filing an application to obtain an ESP from the NRC for the Callaway energy center site. An ESP approves a specific location for a nuclear facility; however, additional licenses would be required for the specific type and design of nuclear facility to be built at that site. An ESP does not authorize construction of a plant. An ESP is valid for 20 years and potentially could be renewed for up to an additional 20 years. Attempts to pass legislation to maintain an option for nuclear power in the state of Missouri by recovering the costs of the ESP, subject to appropriate consumer protections, were not successful during the 2011 spring Missouri legislative session. However, support for nuclear power exists in the state of Missouri, which could lead to the passage of an ESP recovery mechanism in future legislative sessions. Ameren Missouri's pursuit of an ESP is dependent upon enactment of a legislative framework ensuring cost recovery.

As of June 30, 2011, Ameren Missouri had capitalized approximately $67 million relating to its efforts to construct a new nuclear unit. All of these incurred costs will remain capitalized while management assesses options to maximize the value of its investment in this project. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination was made.

Credit Facility Borrowings and Liquidity
6 Months Ended
Jun. 30, 2011
Credit Facility Borrowings and Liquidity
Text Block 
Ameren Illinois [Member]
 
Credit Facility Borrowings and Liquidity
Text Block 
Ameren Energy Generating Company [Member]
 
Credit Facility Borrowings and Liquidity
Text Block 
Union Electric Company [Member]
 
Credit Facility Borrowings and Liquidity
Text Block 
Credit Facility Borrowings and Liquidity 

NOTE 3 - CREDIT FACILITY BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed bank credit facilities, or commercial paper issuances.

The following tables summarize the borrowing activity and relevant interest rates under credit agreements as of June 30, 2011, and excludes issued letters of credit:

 

2010 Missouri Credit Agreement ($800 million)    Ameren (Parent)     Ameren Missouri     Total  

Average daily borrowings outstanding during 2011

    $ 181      $ -      $ 181   

Outstanding credit facility borrowings at period end

      200        -        200   

Weighted-average interest rate during 2011

      2.31 %      -        2.31 % 

Peak credit facility borrowings during 2011(a)

    $ 340      $ -      $ 340   

Peak interest rate during 2011

      4.30 %      -        4.30 % 
      
2010 Genco Credit Agreement ($500 million)      Ameren (Parent)        Genco        Total   

Average daily borrowings outstanding during 2011

    $ -      $ 83      $ 83   

Outstanding credit facility borrowings at period end

      -        -        -   

Weighted-average interest rate during 2011

      -        2.30 %      2.30 % 

Peak credit facility borrowings during 2011(a)

    $ -      $ 100      $ 100   

Peak interest rate during 2011

      -        2.31 %      2.31 % 

 

(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings by the Ameren Companies under all credit facilities during the first six months of 2011 were $440 million.

Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the six months ended June 30, 2011.

The 2010 Credit Agreements are used for cash borrowings, to issue letters of credit, and to support borrowings under Ameren's and Ameren Missouri's $500 million commercial paper programs. Any of the 2010 Credit Agreements are available to Ameren to support its commercial paper programs, subject to borrowing sublimits. At June 30, 2011, Ameren had $317 million of commercial paper outstanding and $15 million of letters of credit outstanding. Based on outstanding borrowings and letters of credit issued under the 2010 Credit Agreements as of June 30, 2011, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available under the 2010 Credit Agreements at June 30, 2011, was $1.6 billion.

In June 2011, Ameren Missouri received approval from the MoPSC to extend the expiration of its borrowing sublimit under the 2010 Missouri Credit Agreement to September 10, 2013.

Other Agreements

On June 2, 2010, Ameren entered into a $20 million revolving credit facility ($20 Million Facility) that matures on June 1, 2012. The $20 Million Facility has been fully drawn since June 15, 2010. Borrowings under the $20 Million Facility bear interest at a rate equal to the applicable LIBOR plus 2.25% per annum. The obligations of Ameren under the $20 Million Facility are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the facility.

Commercial Paper

The 2010 Credit Agreements are used to support Ameren's and Ameren Missouri's commercial paper programs. Ameren may at its discretion use any of the 2010 Credit Agreements to support its commercial paper program, subject to its applicable sublimit. At June 30, 2011, Ameren had $317 million of commercial paper outstanding, which reduced the available amounts under these agreements. During the first six months of 2011, Ameren had average daily commercial paper balances outstanding of $338 million with a weighted-average interest rate of 0.87%. The peak short-term commercial paper outstanding and peak interest rate during the first six months of 2011 were $400 million and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants contained in the 2010 Credit Agreements and the $20 Million Facility. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation), and required regulatory authorizations. In addition, solely with respect to borrowings under the 2010 Illinois Credit Agreement, it is a condition precedent to any such borrowing that, at the time of and after giving effect to such borrowing, the borrower will not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 2010 Credit Agreements also 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 affiliates, and to merge with other entities.

The 2010 Credit Agreements require each of Ameren, Ameren Missouri, Ameren Illinois and Genco to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of June 30, 2011, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 47%, 40% and 45%, for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. In addition, under the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, as applicable. Ameren's ratio as of June 30, 2011, was 5.0 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

The $20 Million Facility requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated capitalization pursuant to a defined calculation set forth in the agreement. As of June 30, 2011, Ameren's consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility, was 49%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any of the 2010 Credit Agreements or Ameren's indenture.

 

None of the Ameren Companies' credit agreements or other financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At June 30, 2011, management believes that the Ameren Companies were in compliance with their credit agreements' provisions and covenants.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Through the utility money pool, Ameren Missouri, Ameren Illinois and Ameren Services may access the committed credit facilities as both lenders and borrowers. Ameren and AERG may participate in the utility money pool only as lenders. Ameren Services administers the utility money pool and tracks internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2010 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 by their affiliates, but increased to the extent that the pool participants have surplus funds or contribute funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. There were no utility money pool borrowings during the three and six months ended June 30, 2011.

Non-state-regulated Subsidiary

Ameren Services, Resources Company, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from the 2010 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by Ameren's subsidiaries, but is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. See the discussion above for the amount available under the 2010 Credit Agreements at June 30, 2011. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren's non-state-regulated activities. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and six months ended June 30, 2011, was 0.72% and 0.93%, respectively (2010 - 1.0% and 0.81%, 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 six months ended June 30, 2011.

Credit Facility Borrowings and Liquidity 

NOTE 3 - CREDIT FACILITY BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed bank credit facilities, or commercial paper issuances.

The following tables summarize the borrowing activity and relevant interest rates under credit agreements as of June 30, 2011, and excludes issued letters of credit:

 

2010 Missouri Credit Agreement ($800 million)    Ameren (Parent)     Ameren Missouri     Total  

Average daily borrowings outstanding during 2011

    $ 181      $ -      $ 181   

Outstanding credit facility borrowings at period end

      200        -        200   

Weighted-average interest rate during 2011

      2.31 %      -        2.31 % 

Peak credit facility borrowings during 2011(a)

    $ 340      $ -      $ 340   

Peak interest rate during 2011

      4.30 %      -        4.30 % 
      
2010 Genco Credit Agreement ($500 million)      Ameren (Parent)        Genco        Total   

Average daily borrowings outstanding during 2011

    $ -      $ 83      $ 83   

Outstanding credit facility borrowings at period end

      -        -        -   

Weighted-average interest rate during 2011

      -        2.30 %      2.30 % 

Peak credit facility borrowings during 2011(a)

    $ -      $ 100      $ 100   

Peak interest rate during 2011

      -        2.31 %      2.31 % 

 

(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings by the Ameren Companies under all credit facilities during the first six months of 2011 were $440 million.

Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the six months ended June 30, 2011.

The 2010 Credit Agreements are used for cash borrowings, to issue letters of credit, and to support borrowings under Ameren's and Ameren Missouri's $500 million commercial paper programs. Any of the 2010 Credit Agreements are available to Ameren to support its commercial paper programs, subject to borrowing sublimits. At June 30, 2011, Ameren had $317 million of commercial paper outstanding and $15 million of letters of credit outstanding. Based on outstanding borrowings and letters of credit issued under the 2010 Credit Agreements as of June 30, 2011, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available under the 2010 Credit Agreements at June 30, 2011, was $1.6 billion.

In June 2011, Ameren Missouri received approval from the MoPSC to extend the expiration of its borrowing sublimit under the 2010 Missouri Credit Agreement to September 10, 2013.

Other Agreements

On June 2, 2010, Ameren entered into a $20 million revolving credit facility ($20 Million Facility) that matures on June 1, 2012. The $20 Million Facility has been fully drawn since June 15, 2010. Borrowings under the $20 Million Facility bear interest at a rate equal to the applicable LIBOR plus 2.25% per annum. The obligations of Ameren under the $20 Million Facility are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the facility.

Commercial Paper

The 2010 Credit Agreements are used to support Ameren's and Ameren Missouri's commercial paper programs. Ameren may at its discretion use any of the 2010 Credit Agreements to support its commercial paper program, subject to its applicable sublimit. At June 30, 2011, Ameren had $317 million of commercial paper outstanding, which reduced the available amounts under these agreements. During the first six months of 2011, Ameren had average daily commercial paper balances outstanding of $338 million with a weighted-average interest rate of 0.87%. The peak short-term commercial paper outstanding and peak interest rate during the first six months of 2011 were $400 million and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants contained in the 2010 Credit Agreements and the $20 Million Facility. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation), and required regulatory authorizations. In addition, solely with respect to borrowings under the 2010 Illinois Credit Agreement, it is a condition precedent to any such borrowing that, at the time of and after giving effect to such borrowing, the borrower will not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 2010 Credit Agreements also 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 affiliates, and to merge with other entities.

The 2010 Credit Agreements require each of Ameren, Ameren Missouri, Ameren Illinois and Genco to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of June 30, 2011, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 47%, 40% and 45%, for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. In addition, under the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, as applicable. Ameren's ratio as of June 30, 2011, was 5.0 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

The $20 Million Facility requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated capitalization pursuant to a defined calculation set forth in the agreement. As of June 30, 2011, Ameren's consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility, was 49%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any of the 2010 Credit Agreements or Ameren's indenture.

 

None of the Ameren Companies' credit agreements or other financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At June 30, 2011, management believes that the Ameren Companies were in compliance with their credit agreements' provisions and covenants.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Through the utility money pool, Ameren Missouri, Ameren Illinois and Ameren Services may access the committed credit facilities as both lenders and borrowers. Ameren and AERG may participate in the utility money pool only as lenders. Ameren Services administers the utility money pool and tracks internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2010 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 by their affiliates, but increased to the extent that the pool participants have surplus funds or contribute funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. There were no utility money pool borrowings during the three and six months ended June 30, 2011.

Non-state-regulated Subsidiary

Ameren Services, Resources Company, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from the 2010 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by Ameren's subsidiaries, but is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. See the discussion above for the amount available under the 2010 Credit Agreements at June 30, 2011. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren's non-state-regulated activities. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and six months ended June 30, 2011, was 0.72% and 0.93%, respectively (2010 - 1.0% and 0.81%, 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 six months ended June 30, 2011.

Credit Facility Borrowings and Liquidity 

NOTE 3 - CREDIT FACILITY BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed bank credit facilities, or commercial paper issuances.

The following tables summarize the borrowing activity and relevant interest rates under credit agreements as of June 30, 2011, and excludes issued letters of credit:

 

2010 Missouri Credit Agreement ($800 million)    Ameren (Parent)     Ameren Missouri     Total  

Average daily borrowings outstanding during 2011

    $ 181      $ -      $ 181   

Outstanding credit facility borrowings at period end

      200        -        200   

Weighted-average interest rate during 2011

      2.31 %      -        2.31 % 

Peak credit facility borrowings during 2011(a)

    $ 340      $ -      $ 340   

Peak interest rate during 2011

      4.30 %      -        4.30 % 
      
2010 Genco Credit Agreement ($500 million)      Ameren (Parent)        Genco        Total   

Average daily borrowings outstanding during 2011

    $ -      $ 83      $ 83   

Outstanding credit facility borrowings at period end

      -        -        -   

Weighted-average interest rate during 2011

      -        2.30 %      2.30 % 

Peak credit facility borrowings during 2011(a)

    $ -      $ 100      $ 100   

Peak interest rate during 2011

      -        2.31 %      2.31 % 

 

(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings by the Ameren Companies under all credit facilities during the first six months of 2011 were $440 million.

Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the six months ended June 30, 2011.

The 2010 Credit Agreements are used for cash borrowings, to issue letters of credit, and to support borrowings under Ameren's and Ameren Missouri's $500 million commercial paper programs. Any of the 2010 Credit Agreements are available to Ameren to support its commercial paper programs, subject to borrowing sublimits. At June 30, 2011, Ameren had $317 million of commercial paper outstanding and $15 million of letters of credit outstanding. Based on outstanding borrowings and letters of credit issued under the 2010 Credit Agreements as of June 30, 2011, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available under the 2010 Credit Agreements at June 30, 2011, was $1.6 billion.

In June 2011, Ameren Missouri received approval from the MoPSC to extend the expiration of its borrowing sublimit under the 2010 Missouri Credit Agreement to September 10, 2013.

Other Agreements

On June 2, 2010, Ameren entered into a $20 million revolving credit facility ($20 Million Facility) that matures on June 1, 2012. The $20 Million Facility has been fully drawn since June 15, 2010. Borrowings under the $20 Million Facility bear interest at a rate equal to the applicable LIBOR plus 2.25% per annum. The obligations of Ameren under the $20 Million Facility are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the facility.

Commercial Paper

The 2010 Credit Agreements are used to support Ameren's and Ameren Missouri's commercial paper programs. Ameren may at its discretion use any of the 2010 Credit Agreements to support its commercial paper program, subject to its applicable sublimit. At June 30, 2011, Ameren had $317 million of commercial paper outstanding, which reduced the available amounts under these agreements. During the first six months of 2011, Ameren had average daily commercial paper balances outstanding of $338 million with a weighted-average interest rate of 0.87%. The peak short-term commercial paper outstanding and peak interest rate during the first six months of 2011 were $400 million and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants contained in the 2010 Credit Agreements and the $20 Million Facility. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation), and required regulatory authorizations. In addition, solely with respect to borrowings under the 2010 Illinois Credit Agreement, it is a condition precedent to any such borrowing that, at the time of and after giving effect to such borrowing, the borrower will not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 2010 Credit Agreements also 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 affiliates, and to merge with other entities.

The 2010 Credit Agreements require each of Ameren, Ameren Missouri, Ameren Illinois and Genco to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of June 30, 2011, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 47%, 40% and 45%, for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. In addition, under the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, as applicable. Ameren's ratio as of June 30, 2011, was 5.0 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

The $20 Million Facility requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated capitalization pursuant to a defined calculation set forth in the agreement. As of June 30, 2011, Ameren's consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility, was 49%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any of the 2010 Credit Agreements or Ameren's indenture.

 

None of the Ameren Companies' credit agreements or other financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At June 30, 2011, management believes that the Ameren Companies were in compliance with their credit agreements' provisions and covenants.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Through the utility money pool, Ameren Missouri, Ameren Illinois and Ameren Services may access the committed credit facilities as both lenders and borrowers. Ameren and AERG may participate in the utility money pool only as lenders. Ameren Services administers the utility money pool and tracks internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2010 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 by their affiliates, but increased to the extent that the pool participants have surplus funds or contribute funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. There were no utility money pool borrowings during the three and six months ended June 30, 2011.

Non-state-regulated Subsidiary

Ameren Services, Resources Company, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from the 2010 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by Ameren's subsidiaries, but is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. See the discussion above for the amount available under the 2010 Credit Agreements at June 30, 2011. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren's non-state-regulated activities. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and six months ended June 30, 2011, was 0.72% and 0.93%, respectively (2010 - 1.0% and 0.81%, 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 six months ended June 30, 2011.

Credit Facility Borrowings and Liquidity 

NOTE 3 - CREDIT FACILITY BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed bank credit facilities, or commercial paper issuances.

The following tables summarize the borrowing activity and relevant interest rates under credit agreements as of June 30, 2011, and excludes issued letters of credit:

 

2010 Missouri Credit Agreement ($800 million)    Ameren (Parent)     Ameren Missouri     Total  

Average daily borrowings outstanding during 2011

    $ 181      $ -      $ 181   

Outstanding credit facility borrowings at period end

      200        -        200   

Weighted-average interest rate during 2011

      2.31 %      -        2.31 % 

Peak credit facility borrowings during 2011(a)

    $ 340      $ -      $ 340   

Peak interest rate during 2011

      4.30 %      -        4.30 % 
      
2010 Genco Credit Agreement ($500 million)      Ameren (Parent)        Genco        Total   

Average daily borrowings outstanding during 2011

    $ -      $ 83      $ 83   

Outstanding credit facility borrowings at period end

      -        -        -   

Weighted-average interest rate during 2011

      -        2.30 %      2.30 % 

Peak credit facility borrowings during 2011(a)

    $ -      $ 100      $ 100   

Peak interest rate during 2011

      -        2.31 %      2.31 % 

 

(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings by the Ameren Companies under all credit facilities during the first six months of 2011 were $440 million.

Neither Ameren nor Ameren Illinois borrowed under the 2010 Illinois Credit Agreement during the six months ended June 30, 2011.

The 2010 Credit Agreements are used for cash borrowings, to issue letters of credit, and to support borrowings under Ameren's and Ameren Missouri's $500 million commercial paper programs. Any of the 2010 Credit Agreements are available to Ameren to support its commercial paper programs, subject to borrowing sublimits. At June 30, 2011, Ameren had $317 million of commercial paper outstanding and $15 million of letters of credit outstanding. Based on outstanding borrowings and letters of credit issued under the 2010 Credit Agreements as of June 30, 2011, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available under the 2010 Credit Agreements at June 30, 2011, was $1.6 billion.

In June 2011, Ameren Missouri received approval from the MoPSC to extend the expiration of its borrowing sublimit under the 2010 Missouri Credit Agreement to September 10, 2013.

Other Agreements

On June 2, 2010, Ameren entered into a $20 million revolving credit facility ($20 Million Facility) that matures on June 1, 2012. The $20 Million Facility has been fully drawn since June 15, 2010. Borrowings under the $20 Million Facility bear interest at a rate equal to the applicable LIBOR plus 2.25% per annum. The obligations of Ameren under the $20 Million Facility are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the facility.

Commercial Paper

The 2010 Credit Agreements are used to support Ameren's and Ameren Missouri's commercial paper programs. Ameren may at its discretion use any of the 2010 Credit Agreements to support its commercial paper program, subject to its applicable sublimit. At June 30, 2011, Ameren had $317 million of commercial paper outstanding, which reduced the available amounts under these agreements. During the first six months of 2011, Ameren had average daily commercial paper balances outstanding of $338 million with a weighted-average interest rate of 0.87%. The peak short-term commercial paper outstanding and peak interest rate during the first six months of 2011 were $400 million and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants contained in the 2010 Credit Agreements and the $20 Million Facility. See Note 4 - Credit Facility Borrowings and Liquidity under Part II, Item 8, of the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions to borrowings and issuances of letters of credit, including the absence of default or unmatured default, material accuracy of representations and warranties (excluding any representation after the closing date as to the absence of material adverse change and material litigation), and required regulatory authorizations. In addition, solely with respect to borrowings under the 2010 Illinois Credit Agreement, it is a condition precedent to any such borrowing that, at the time of and after giving effect to such borrowing, the borrower will not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 2010 Credit Agreements also 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 affiliates, and to merge with other entities.

The 2010 Credit Agreements require each of Ameren, Ameren Missouri, Ameren Illinois and Genco to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of June 30, 2011, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 47%, 40% and 45%, for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. In addition, under the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2010 Genco Credit Agreement and the 2010 Illinois Credit Agreement, as applicable. Ameren's ratio as of June 30, 2011, was 5.0 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

The $20 Million Facility requires Ameren to maintain consolidated indebtedness of not more than 65% of its consolidated capitalization pursuant to a defined calculation set forth in the agreement. As of June 30, 2011, Ameren's consolidated indebtedness ratio, calculated in accordance with the provisions of the $20 Million Facility, was 49%. Failure by Ameren to satisfy this covenant would constitute an immediate default under the $20 Million Facility but, given the size of the facility, would not trigger an Ameren default under any of the 2010 Credit Agreements or Ameren's indenture.

 

None of the Ameren Companies' credit agreements or other financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At June 30, 2011, management believes that the Ameren Companies were in compliance with their credit agreements' provisions and covenants.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements.

Utility

Through the utility money pool, Ameren Missouri, Ameren Illinois and Ameren Services may access the committed credit facilities as both lenders and borrowers. Ameren and AERG may participate in the utility money pool only as lenders. Ameren Services administers the utility money pool and tracks internal and external funds separately. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2010 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 by their affiliates, but increased to the extent that the pool participants have surplus funds or contribute funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. There were no utility money pool borrowings during the three and six months ended June 30, 2011.

Non-state-regulated Subsidiary

Ameren Services, Resources Company, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from the 2010 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by Ameren's subsidiaries, but is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. See the discussion above for the amount available under the 2010 Credit Agreements at June 30, 2011. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren's non-state-regulated activities. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and six months ended June 30, 2011, was 0.72% and 0.93%, respectively (2010 - 1.0% and 0.81%, 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 six months ended June 30, 2011.

Long-Term Debt and Equity Financings
6 Months Ended
Jun. 30, 2011
Long-Term Debt and Equity Financings
Text Block 
Ameren Energy Generating Company [Member]
 
Long-Term Debt and Equity Financings
Text Block 
Ameren Illinois [Member]
 
Long-Term Debt and Equity Financings
Text Block 
Union Electric Company [Member]
 
Long-Term Debt and Equity Financings
Text Block 
Long-Term Debt and Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to effective SEC Form S-3 registration statements, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.6 million new shares of common stock valued at $15 million and 1.2 million new shares valued at $32 million in the three and six months ended June 30, 2011, respectively.

Ameren Illinois

In June 2011, Ameren Illinois' 6.625% $150 million senior secured notes matured and were repaid and retired using available cash on hand.

 

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indenture provisions 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. However, not meeting these ratios would not result in a default under these covenants and provisions. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended June 30, 2011, at an assumed interest rate of 7% and dividend rate of 8%.

 

     

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

    ³2.0      3.4       $ 2,070      ³2.5      99.0       $ 1,650   

Ameren Illinois

    ³2.0      7.0         3,230 (d)    ³1.5      3.1         203   

 

(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $91 million and $765 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 by the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.

Ameren Missouri, Ameren Illinois and Genco as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Missouri's mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by Ameren Missouri. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.9 billion of free and unrestricted retained earnings at June 30, 2011.

Ameren Illinois' articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization following the Ameren Illinois Merger and AERG distribution. As of June 30, 2011, Ameren Illinois' ratio of common stock equity to total capitalization was 56%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, make certain principal or interest payments, make certain loans to or investments in affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended and as of June 30, 2011:

 

     

Required Interest

Coverage Ratio

   

Actual Interest

Coverage Ratio

   

Required Debt-to-

Capital Ratio

   

Actual Debt-to-

Capital Ratio

Genco    ³1.75(a) /2.50(b)    4.6    £60%(b)    43%

 

(a) A minimum interest coverage ratio of 1.75 is required for Genco to make certain restricted payments, as defined, including specified dividend, principal and interest payments on certain subordinated intercompany borrowings. As of the date of the restricted payment, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.
(b) A minimum interest coverage ratio of 2.50 for the most recently ended four fiscal quarters and a debt-to-capital ratio of no greater than 60% are required for Genco to incur additional indebtedness, as defined, other than permitted indebtedness, as defined. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests.

 

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P, after giving effect to additional indebtedness, each provide a rating affirmation of the rating then existing with respect with securities issued under the indenture.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At June 30, 2011, 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.

Long-Term Debt and Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to effective SEC Form S-3 registration statements, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.6 million new shares of common stock valued at $15 million and 1.2 million new shares valued at $32 million in the three and six months ended June 30, 2011, respectively.

Ameren Illinois

In June 2011, Ameren Illinois' 6.625% $150 million senior secured notes matured and were repaid and retired using available cash on hand.

 

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indenture provisions 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. However, not meeting these ratios would not result in a default under these covenants and provisions. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended June 30, 2011, at an assumed interest rate of 7% and dividend rate of 8%.

 

     

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

    ³2.0      3.4       $ 2,070      ³2.5      99.0       $ 1,650   

Ameren Illinois

    ³2.0      7.0         3,230 (d)    ³1.5      3.1         203   

 

(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $91 million and $765 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 by the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.

Ameren Missouri, Ameren Illinois and Genco as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Missouri's mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by Ameren Missouri. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.9 billion of free and unrestricted retained earnings at June 30, 2011.

Ameren Illinois' articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization following the Ameren Illinois Merger and AERG distribution. As of June 30, 2011, Ameren Illinois' ratio of common stock equity to total capitalization was 56%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, make certain principal or interest payments, make certain loans to or investments in affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended and as of June 30, 2011:

 

     

Required Interest

Coverage Ratio

   

Actual Interest

Coverage Ratio

   

Required Debt-to-

Capital Ratio

   

Actual Debt-to-

Capital Ratio

Genco    ³1.75(a) /2.50(b)    4.6    £60%(b)    43%

 

(a) A minimum interest coverage ratio of 1.75 is required for Genco to make certain restricted payments, as defined, including specified dividend, principal and interest payments on certain subordinated intercompany borrowings. As of the date of the restricted payment, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.
(b) A minimum interest coverage ratio of 2.50 for the most recently ended four fiscal quarters and a debt-to-capital ratio of no greater than 60% are required for Genco to incur additional indebtedness, as defined, other than permitted indebtedness, as defined. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests.

 

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P, after giving effect to additional indebtedness, each provide a rating affirmation of the rating then existing with respect with securities issued under the indenture.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At June 30, 2011, 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.

Long-Term Debt and Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to effective SEC Form S-3 registration statements, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.6 million new shares of common stock valued at $15 million and 1.2 million new shares valued at $32 million in the three and six months ended June 30, 2011, respectively.

Ameren Illinois

In June 2011, Ameren Illinois' 6.625% $150 million senior secured notes matured and were repaid and retired using available cash on hand.

 

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indenture provisions 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. However, not meeting these ratios would not result in a default under these covenants and provisions. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended June 30, 2011, at an assumed interest rate of 7% and dividend rate of 8%.

 

     

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

    ³2.0      3.4       $ 2,070      ³2.5      99.0       $ 1,650   

Ameren Illinois

    ³2.0      7.0         3,230 (d)    ³1.5      3.1         203   

 

(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $91 million and $765 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 by the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.

Ameren Missouri, Ameren Illinois and Genco as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Missouri's mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by Ameren Missouri. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.9 billion of free and unrestricted retained earnings at June 30, 2011.

Ameren Illinois' articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization following the Ameren Illinois Merger and AERG distribution. As of June 30, 2011, Ameren Illinois' ratio of common stock equity to total capitalization was 56%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, make certain principal or interest payments, make certain loans to or investments in affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended and as of June 30, 2011:

 

     

Required Interest

Coverage Ratio

   

Actual Interest

Coverage Ratio

   

Required Debt-to-

Capital Ratio

   

Actual Debt-to-

Capital Ratio

Genco    ³1.75(a) /2.50(b)    4.6    £60%(b)    43%

 

(a) A minimum interest coverage ratio of 1.75 is required for Genco to make certain restricted payments, as defined, including specified dividend, principal and interest payments on certain subordinated intercompany borrowings. As of the date of the restricted payment, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.
(b) A minimum interest coverage ratio of 2.50 for the most recently ended four fiscal quarters and a debt-to-capital ratio of no greater than 60% are required for Genco to incur additional indebtedness, as defined, other than permitted indebtedness, as defined. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests.

 

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P, after giving effect to additional indebtedness, each provide a rating affirmation of the rating then existing with respect with securities issued under the indenture.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At June 30, 2011, 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.

Long-Term Debt and Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Ameren

Under DRPlus, pursuant to effective SEC Form S-3 registration statements, and under our 401(k) plan, pursuant to an effective SEC Form S-8 registration statement, Ameren issued a total of 0.6 million new shares of common stock valued at $15 million and 1.2 million new shares valued at $32 million in the three and six months ended June 30, 2011, respectively.

Ameren Illinois

In June 2011, Ameren Illinois' 6.625% $150 million senior secured notes matured and were repaid and retired using available cash on hand.

 

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indenture provisions 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. However, not meeting these ratios would not result in a default under these covenants and provisions. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended June 30, 2011, at an assumed interest rate of 7% and dividend rate of 8%.

 

     

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

    ³2.0      3.4       $ 2,070      ³2.5      99.0       $ 1,650   

Ameren Illinois

    ³2.0      7.0         3,230 (d)    ³1.5      3.1         203   

 

(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(b) Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $91 million and $765 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 by the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 2010 Credit Agreements, constitutes a default under the indenture, unless such past due or accelerated debt is discharged or the acceleration is rescinded or annulled within a specified period.

Ameren Missouri, Ameren Illinois and Genco as well as certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Missouri's mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by Ameren Missouri. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.9 billion of free and unrestricted retained earnings at June 30, 2011.

Ameren Illinois' articles of incorporation require its dividend payments on common stock to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Ameren Illinois committed to FERC to maintain a minimum 30% ratio of common stock equity to total capitalization following the Ameren Illinois Merger and AERG distribution. As of June 30, 2011, Ameren Illinois' ratio of common stock equity to total capitalization was 56%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and/or debt-to-capital ratios in order for Genco to pay dividends, make certain principal or interest payments, make certain loans to or investments in affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended and as of June 30, 2011:

 

     

Required Interest

Coverage Ratio

   

Actual Interest

Coverage Ratio

   

Required Debt-to-

Capital Ratio

   

Actual Debt-to-

Capital Ratio

Genco    ³1.75(a) /2.50(b)    4.6    £60%(b)    43%

 

(a) A minimum interest coverage ratio of 1.75 is required for Genco to make certain restricted payments, as defined, including specified dividend, principal and interest payments on certain subordinated intercompany borrowings. As of the date of the restricted payment, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.
(b) A minimum interest coverage ratio of 2.50 for the most recently ended four fiscal quarters and a debt-to-capital ratio of no greater than 60% are required for Genco to incur additional indebtedness, as defined, other than permitted indebtedness, as defined. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests.

 

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P, after giving effect to additional indebtedness, each provide a rating affirmation of the rating then existing with respect with securities issued under the indenture.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At June 30, 2011, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

Other Income and Expenses
6 Months Ended
Jun. 30, 2011
Other Income and Expenses
Text Block 
Ameren Energy Generating Company [Member]
 
Other Income and Expenses
Text Block 
Ameren Illinois [Member]
 
Other Income and Expenses
Text Block 
Union Electric Company [Member]
 
Other Income and Expenses
Text Block 
Other Income and Expenses 

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and six months ended June 30, 2011, and 2010:

 

      Three Months      Six Months  
          2011              2010              2011              2010      

Ameren:(a)

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 13       $ 15       $ 26   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      1         1         2         2   

Other

      -         3         2         4   

Total miscellaneous income

    $ 17       $ 24       $ 33       $ 46   

Miscellaneous expense:

            

Donations

    $ 1       $ 1       $ 3       $ 3   

Other

      4         1         7         6   

Total miscellaneous expense

    $ 5       $ 2       $ 10       $ 9   

Ameren Missouri:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 12       $ 14       $ 25   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      -         1         1         1   

Other

      -         -         -         1   

Total miscellaneous income

    $ 16       $ 20       $ 29       $ 41   

Miscellaneous expense:

            

Donations

    $ 1       $ -       $ 2       $ 1   

Other

      2         1         4         2   

Total miscellaneous expense

    $ 3       $ 1       $ 6       $ 3   

Ameren Illinois:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ -       $ 1       $ 1       $ 1   

Interest and dividend income

      -         -         -         1   

Other

      1         1         2         2   

Total miscellaneous income

    $ 1       $ 2       $ 3       $ 4   

Miscellaneous expense:

            

Donations

    $ -       $ 1       $ -       $ 1   

Other

      1         -         2         3   

Total miscellaneous expense

    $ 1       $ 1       $ 2       $ 4   

Genco:

            

Miscellaneous income:

            

Other

    $ -       $ 1       $ -       $ 1   

Total miscellaneous income

    $ -       $ 1       $ -       $ 1   

Miscellaneous expense:

            

Other

    $ -       $ -       $ -       $ 1   

Total miscellaneous expense

    $ -       $ -       $ -       $ 1   

 

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

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and six months ended June 30, 2011, and 2010:

 

      Three Months      Six Months  
          2011              2010              2011              2010      

Ameren:(a)

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 13       $ 15       $ 26   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      1         1         2         2   

Other

      -         3         2         4   

Total miscellaneous income

    $ 17       $ 24       $ 33       $ 46   

Miscellaneous expense:

            

Donations

    $ 1       $ 1       $ 3       $ 3   

Other

      4         1         7         6   

Total miscellaneous expense

    $ 5       $ 2       $ 10       $ 9   

Ameren Missouri:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 12       $ 14       $ 25   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      -         1         1         1   

Other

      -         -         -         1   

Total miscellaneous income

    $ 16       $ 20       $ 29       $ 41   

Miscellaneous expense:

            

Donations

    $ 1       $ -       $ 2       $ 1   

Other

      2         1         4         2   

Total miscellaneous expense

    $ 3       $ 1       $ 6       $ 3   

Ameren Illinois:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ -       $ 1       $ 1       $ 1   

Interest and dividend income

      -         -         -         1   

Other

      1         1         2         2   

Total miscellaneous income

    $ 1       $ 2       $ 3       $ 4   

Miscellaneous expense:

            

Donations

    $ -       $ 1       $ -       $ 1   

Other

      1         -         2         3   

Total miscellaneous expense

    $ 1       $ 1       $ 2       $ 4   

Genco:

            

Miscellaneous income:

            

Other

    $ -       $ 1       $ -       $ 1   

Total miscellaneous income

    $ -       $ 1       $ -       $ 1   

Miscellaneous expense:

            

Other

    $ -       $ -       $ -       $ 1   

Total miscellaneous expense

    $ -       $ -       $ -       $ 1   

 

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

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and six months ended June 30, 2011, and 2010:

 

      Three Months      Six Months  
          2011              2010              2011              2010      

Ameren:(a)

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 13       $ 15       $ 26   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      1         1         2         2   

Other

      -         3         2         4   

Total miscellaneous income

    $ 17       $ 24       $ 33       $ 46   

Miscellaneous expense:

            

Donations

    $ 1       $ 1       $ 3       $ 3   

Other

      4         1         7         6   

Total miscellaneous expense

    $ 5       $ 2       $ 10       $ 9   

Ameren Missouri:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 12       $ 14       $ 25   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      -         1         1         1   

Other

      -         -         -         1   

Total miscellaneous income

    $ 16       $ 20       $ 29       $ 41   

Miscellaneous expense:

            

Donations

    $ 1       $ -       $ 2       $ 1   

Other

      2         1         4         2   

Total miscellaneous expense

    $ 3       $ 1       $ 6       $ 3   

Ameren Illinois:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ -       $ 1       $ 1       $ 1   

Interest and dividend income

      -         -         -         1   

Other

      1         1         2         2   

Total miscellaneous income

    $ 1       $ 2       $ 3       $ 4   

Miscellaneous expense:

            

Donations

    $ -       $ 1       $ -       $ 1   

Other

      1         -         2         3   

Total miscellaneous expense

    $ 1       $ 1       $ 2       $ 4   

Genco:

            

Miscellaneous income:

            

Other

    $ -       $ 1       $ -       $ 1   

Total miscellaneous income

    $ -       $ 1       $ -       $ 1   

Miscellaneous expense:

            

Other

    $ -       $ -       $ -       $ 1   

Total miscellaneous expense

    $ -       $ -       $ -       $ 1   

 

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

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and six months ended June 30, 2011, and 2010:

 

      Three Months      Six Months  
          2011              2010              2011              2010      

Ameren:(a)

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 13       $ 15       $ 26   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      1         1         2         2   

Other

      -         3         2         4   

Total miscellaneous income

    $ 17       $ 24       $ 33       $ 46   

Miscellaneous expense:

            

Donations

    $ 1       $ 1       $ 3       $ 3   

Other

      4         1         7         6   

Total miscellaneous expense

    $ 5       $ 2       $ 10       $ 9   

Ameren Missouri:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 12       $ 14       $ 25   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      -         1         1         1   

Other

      -         -         -         1   

Total miscellaneous income

    $ 16       $ 20       $ 29       $ 41   

Miscellaneous expense:

            

Donations

    $ 1       $ -       $ 2       $ 1   

Other

      2         1         4         2   

Total miscellaneous expense

    $ 3       $ 1       $ 6       $ 3   

Ameren Illinois:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ -       $ 1       $ 1       $ 1   

Interest and dividend income

      -         -         -         1   

Other

      1         1         2         2   

Total miscellaneous income

    $ 1       $ 2       $ 3       $ 4   

Miscellaneous expense:

            

Donations

    $ -       $ 1       $ -       $ 1   

Other

      1         -         2         3   

Total miscellaneous expense

    $ 1       $ 1       $ 2       $ 4   

Genco:

            

Miscellaneous income:

            

Other

    $ -       $ 1       $ -       $ 1   

Total miscellaneous income

    $ -       $ 1       $ -       $ 1   

Miscellaneous expense:

            

Other

    $ -       $ -       $ -       $ 1   

Total miscellaneous expense

    $ -       $ -       $ -       $ 1   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Derivative Financial Instruments
6 Months Ended
Jun. 30, 2011
Derivative Financial Instruments
Text Block 
Ameren Energy Generating Company [Member]
 
Derivative Financial Instruments
Text Block 
Ameren Illinois [Member]
 
Derivative Financial Instruments
Text Block 
Union Electric Company [Member]
 
Derivative Financial Instruments
Text Block 
Derivative Financial Instruments 

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, power, and uranium. Such price fluctuations may cause the following:

 

•  

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

 

•  

market values of coal, natural gas, and uranium inventories that differ from the cost of those commodities in inventory; and

 

•  

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross derivative volumes by commodity type as of June 30, 2011, and December 31, 2010:

 

                                                                 
      Quantity (in millions, except as indicated)  
Commodity   

NPNS

Contracts(a)

     Cash Flow
Hedges(b)		     Other
Derivatives(c)		     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2011     2010     2011     2010     2011     2010     2011     2010  

Coal (in tons)

                                                                 

AMO

      36        46        (e )      (e )      (e )      (e )      (e )      (e ) 

Genco

      24        21        (e )      (e )      (e )      (e )      (e )      (e ) 

Other(f)

      6        6        (e )      (e )      (e )      (e )      (e )      (e ) 

Ameren

                     66                        73                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Heating oil (in gallons)

                                                                 

AMO

      (e )      (e )      (e )      (e )      (e )      (e )      62        80   

Genco

      (e )      (e )      (e )      (e )      31        43        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      9        12        (e )      (e ) 

Ameren

     (e )      (e )      (e )      (e )      40        55        62        80   

Natural gas (in mmbtu)

                                                                 

AMO

      10        13        (e )      (e )      3        2        21        21   

AIC

      62        85        (e )      (e )      (e )      (e )      175        173   

Genco

      (e )      (e )      (e )      (e )      3        3        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      20        16        (e )      (e ) 

Ameren

     72        98        (e )      (e )      26        21        196        194   

Power (in megawatthours)

                                                                 

AMO

      2        2        (e )      (e )      1        1        3        5   

AIC

      12        (e )      (e )      (e )      (e )      (e )      31        26   

Genco

      (e )      (e )      (e )      (e )      2        3        (e )      (e ) 

Other(f)

      65        61        21        2        51        57        (14 )      (13 ) 

Ameren

     79        63        21        2        54        61        20        18   

Uranium (pounds in thousands)

                                                                 

AMO

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

Ameren

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

 

(a) Contracts through December 2014, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of June 30, 2011.
(b) Contracts through December 2013 for power as of June 30, 2011.
(c) Contracts through December 2013, December 2012, and May 2015 for heating oil, natural gas, and power, respectively, as of June 30, 2011.
(d) Contracts through December 2013, October 2016, May 2032 and December 2013 for heating oil, natural gas, power, and uranium, respectively, as of June 30, 2011.
(e) Not applicable.
(f) Includes AERG coal and heating oil, Marketing Company natural gas and power, and intercompany eliminations' for power.

Authoritative 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 our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

 

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and Ameren Illinois believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2011, and December 31, 2010:

 

                                     
      Balance Sheet Location   

Ameren(a)

      Ameren Missouri     Ameren Illinois     Genco  

2011:

                                  

Derivative assets designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative assets    $ 5       $ -      $ (b )    $ -   
    

Other assets

      2         -        -        -   
    

Total assets

    $ 7       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative liabilities    $ 3       $ (b )    $ -      $ -   
    

Other deferred credits and liabilities

      4         -        -        -   
    

Total liabilities

    $ 7       $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

                                  

Commodity contracts:

                                       

Heating oil

    MTM derivative assets    $ 49       $ 29      $ (b )    $ 15   
    

Other assets

      23         14        -        7   

Natural gas

    MTM derivative assets      5         -        (b )      1   
    

Other current assets

      -         -        2        -   
    

Other assets

      1         -        -        -   

Power

    MTM derivative assets      100         29        (b )      4   
    

Other current assets

      -         -        1        -   
    

Other assets

      85         1        68        -   
    

Total assets

    $ 263       $ 73      $ 71      $ 27   

Derivative liabilities not designated as hedging instruments(c)

                                  

Commodity contracts:

                                       

Heating oil

    MTM derivative liabilities    $ 4       $ (b )    $ -      $ 1   
    

Other current liabilities

      -         2        -        -   

Natural gas

    MTM derivative liabilities      75         (b )      60        2   
    

Other current liabilities

      -         10        -        -   
    

Other deferred credits and liabilities

      63         10        53        -   

Power

    MTM derivative liabilities      52         (b )      4        2   
    

MTM derivative liabilities - affiliates

      -         (b )      173        1   
    

Other current liabilities

      -         3        -        -   
    

Other deferred credits and liabilities

      14         1        96        -   

Uranium

    MTM derivative liabilities      1         (b )      -        -   
    

Other current liabilities

      -         1        -        -   
    

Other deferred credits and liabilities

      1         1        -        -   
    

Total liabilities

    $ 210       $ 28      $ 386      $ 6   

2010:

                                       

Derivative assets designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative assets    $ 3       $ -      $ (b )    $ -   
     Other assets      2         -        -        -   
    

Total assets

    $ 5       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative liabilities    $ 1       $ (b )    $ -      $ -   
    

Total liabilities

    $                           1       $ -      $ -      $                          -   
      Balance Sheet Location   

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

  

Derivative assets not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Heating oil

    MTM derivative assets    $ 42      $ 24      $ (b )    $ 14   
     Other current assets      -        -        -        -   
     Other assets      22        13        -        7   

Natural gas

    MTM derivative assets      4        1        (b )      1   
     Other current assets      -        -        1        -   
     Other assets      1        -        1        -   

Power

    MTM derivative assets      78        8        (b )      11   
     Other current assets      -        -        2        -   
     Other assets      20        -        6        -   

Uranium

    MTM derivative assets      2        2        (b )      -   
     Other current assets      -        -        -        -   
     Total assets    $ 169      $ 48      $ 10      $ 33   

Derivative liabilities not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Heating oil

    MTM derivative liabilities    $ 12      $ (b )    $ -      $ 4   
     Other current liabilities      -        7        -        -   
     Other deferred credits and liabilities      1        -        -        -   

Natural gas

    MTM derivative liabilities      87        (b )      73        2   
     Other current liabilities      -        11        -        -   
     Other deferred credits and liabilities      84        13        70        -   

Power

    MTM derivative liabilities      61        (b )      9        3   
     MTM derivative liabilities - affiliates      (b )      (b )      172        5   
     Other current liabilities      -        6        -        -   
     Other deferred credits and liabilities      7        -        179        -   
     Total liabilities    $                        252      $ 37      $ 503      $                        14   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Balance sheet line item not applicable to registrant.
(c) Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of June 30, 2011, and December 31, 2010:

 

                                         
     

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

    

Other(a)

  

2011:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 3      $ -      $ -      $ -      $ 3   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

                                         

Heating oil derivative contracts(e)

      35        35        -        -        -   

Natural gas derivative contracts(f)

      (131 )      (20 )      (111 )      -        -   

Power derivative contracts(g)

      91        26        (204 )      -        269   

Uranium derivative contracts(h)

      (2 )      (2 )      -        -        -   

2010:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 8      $ -      $ -      $ -      $ 8   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

                                         

Heating oil derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (165 )      (24 )      (141 )      -        -   

Power derivative contracts(g)

      1        3        (352 )      -        350   

Uranium derivative contracts(h)

      2        2        -        -        -   

 

(a) Includes amounts for Marketing Company and intercompany eliminations.
(b) Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through December 2013 as of June 30, 2011. Current gains of $3 million and $8 million were recorded at Ameren as of June 30, 2011, and December 31, 2010, respectively.
(c) Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at June 30, 2011, and December 31, 2010, was less than $1 million and less than $1 million, respectively. The balance of the gain will be amortized by June 2012.
(d) Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco's April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at June 30, 2011, and December 31, 2010, was a loss of $9 million and $10 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e)

Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through December 2013 as of June 30, 2011. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and Ameren Illinois, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $69 million, $9 million, and $60 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(g) Represents net gains 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 2012 at Ameren Missouri, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $29 million, $28 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $5 million, $2 million, and $177 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(h) Represents net losses and gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of June 30, 2011. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri as of December 31, 2010, 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) 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) North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of June 30, 2011, and December 31, 2010, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

                                                                         
      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                                                                                 

AMO

    $ -       $ 22       $ 2       $ 5       $ 39       $ 7       $ -       $ -       $ 75    

AIC

      -         -         29         -         2         -         -         -         31    

Genco

      -         12         1         1         3         -         4         -         21    

Other(b)

      333         7         7         10         47         217         1         68         690    

Ameren

     333         41         39         16         91         224         5         68         817    

2010:

                                                                                 

AMO

    $ -       $ 21       $ 1       $ 2       $ 5       $ 11       $ 1       $ -       $ 41    

AIC

      -         -         3         -         1         -         -         -         4    

Genco

      -         6         2         1         1         -         6         -         16    

Other(b)

      410         3         10         19         65         539         3         72         1,121    

Ameren

     410         30         16         22         72         550         10         72         1,182    

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.
 

The following table presents the amount of cash collateral held from counterparties, as of June 30, 2011, and December 31, 2010, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

 

                                                                         
      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                                                                                 

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ -       $  -    

2010:

                                                                                 

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ 1       $ 1    

 

(a) Represents amounts held by Marketing Company. As of June 30, 2011, and December 31, 2010, Ameren registrant subsidiaries held no cash collateral.

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. As of June 30, 2011, other collateral consisted of letters of credit in the amount of $16 million, $1 million, $2 million and $13 million held by Ameren, Ameren Missouri, Ameren Illinois and Marketing Company, respectively. As of December 31, 2010, other collateral consisted of letters of credit in the amount of $28 million and $1 million held by Ameren and Ameren Illinois, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2011, and December 31, 2010:

 

                                                                         
      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                                                                                 

AMO

    $ -       $ 10       $ 1       $ 3       $ 33       $ 7       $ -       $ -       $ 54   

AIC

      -         -         27         -         -         -         -         -         27   

Genco

      -         4         1         -         1         -         3         -         9   

Other(b)

      317         4         6         5         35         205         -         67         639   

Ameren

     317         18         35         8         69         212         3         67         729   

2010:

                                                                                 

AMO

    $ -       $ 8       $ -       $ 1       $ 2       $ 10       $ -       $ -       $ 21   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         1         1         1         1         -         5         -         9   

Other(b)

      404         1         8         7         56         513         2         71         1,062   

Ameren

     404         10         11         9         59         523         7         71         1,094   

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies' credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of June 30, 2011, and December 31, 2010, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on June 30, 2011, or December 31, 2010, 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)		  

2011:

                           

Ameren Missouri

    $ 113       $ 5         $                         67   

Ameren Illinois

      207         91         103   

Genco

      49         5         26   

Other(c)

      121         13         59   

Ameren

     490         114         255   

2010:

                           

Ameren Missouri

    $ 105       $ 7         $                        93   

Ameren Illinois

      233         109         111   

Genco

      31         -         28   

Other(c)

      62         18         42   

Ameren

     431         134         274   

 

(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.
(c) Includes amounts for Marketing Company and Ameren (parent).

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three and six months ended June 30, 2011, and 2010, associated with derivative instruments designated as cash flow hedges. See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

 

                                 
     

Gain (Loss)

Recognized in
OCI(a)

    

Location of (Gain) Loss

Reclassified from

OCI into Income(b)

   

(Gain) Loss

Reclassified from

OCI into Income(b)

    

Location of Gain (Loss)

Recognized in Income(c)

   

Gain (Loss)

Recognized

in Income(c)

  

                             Three Months

 

                          

2011:

                                   

Ameren:(d)

                                   

Power

    $ (3 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ 3   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

                                   

Ameren:(d)

                                   

Power

    $ (16 )    Operating Revenues - Electric    $ (10 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

                             Six Months

 

                          

2011:

                                   

Ameren:(d)

                                   

Power

    $ (7 )    Operating Revenues - Electric    $ 2      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

                                   

Ameren:(d)

                                   

Power

    $ 10      Operating Revenues - Electric    $ (14 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

 

(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d) Includes amounts from Ameren registrant and nonregistrant subsidiaries.
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
(f) Less than $1 million.

 

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three and six months ended June 30, 2011, and 2010:

 

                                             
           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               Three Months          Six Months  
                  2011     2010           2011     2010  
Ameren(a)    Heating oil    Operating Expenses - Fuel    $ (9 )    $ (7 )         $ 10      $ (6 ) 
     Natural gas (generation)    Operating Expenses - Fuel      -        -             -        (1 ) 
     Power    Operating Revenues - Electric      (5 )      (11 )           (7 )      20   
         

Total

    $ (14 )    $ (18 )         $ 3      $ 13   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ -           $ (1 )    $ 1   
    

Power

    Operating Revenues - Electric      -        -             -        (1 ) 
          Total    $ -      $ -           $ (1 )    $ -   
Genco    Heating oil    Operating Expenses - Fuel    $ (8 )    $ (5 )         $ 7      $ (4 ) 
    

Natural gas (generation)

    Operating Expenses - Fuel      -        -             -        (1 ) 
    

Power

    Operating Revenues      (1 )      -             (1 )      1   
          Total    $ (9 )    $ (5 )         $ 6      $ (4 ) 

 

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

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and six months ended June 30, 2011, and 2010:

 

                                         
            Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets  
          Three Months          Six Months  
            2011     2010           2011     2010  

Ameren(a)

    Heating oil    $ (13 )    $ (9 )         $ 16      $ (8 ) 
    

Natural gas

      3        25             34        (81 ) 
    

Power

      88        33             90        23   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 75      $ 48           $ 136      $ (68 ) 

Ameren Missouri            

    Heating oil    $ (13 )    $ (9 )         $ 16      $ (8 ) 
    

Natural gas

      1        4             4        (11 ) 
    

Power

      23        (9 )           23        7   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 8      $ (15 )         $ 39      $ (14 ) 

Ameren Illinois

    Natural gas    $ 2      $ 21           $ 30      $ (70 ) 
    

Power

      121        150             148        17   
    

Total

    $ 123      $ 171           $ 178      $ (53 ) 

 

(a) Includes amounts for intercompany eliminations.

As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, Ameren Illinois entered into financial contracts with Marketing Company. These financial contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives that qualify for regulatory deferral by Ameren Illinois. Consequently, Ameren Illinois and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by Ameren Illinois and OCI by Marketing Company. In Ameren's consolidated financial statements, all financial statement effects of the derivative instruments entered into among affiliates were eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts. The following table presents the fair value of the financial contracts included on Ameren Illinois' balance sheet at June 30, 2011, and December 31, 2010:

 

                     
            2011      2010  

AIC

    MTM derivative liabilities - affiliates    $ 173       $ 172   
     Other deferred credits and liabilities      95         178   
     Total    $             268       $             350   
Derivative Financial Instruments 

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, power, and uranium. Such price fluctuations may cause the following:

 

•  

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

 

•  

market values of coal, natural gas, and uranium inventories that differ from the cost of those commodities in inventory; and

 

•  

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross derivative volumes by commodity type as of June 30, 2011, and December 31, 2010:

 

      Quantity (in millions, except as indicated)  
Commodity   

NPNS

Contracts(a)

     Cash Flow
Hedges(b)		     Other
Derivatives(c)		     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2011     2010     2011     2010     2011     2010     2011     2010  

Coal (in tons)

                 

AMO

      36        46        (e )      (e )      (e )      (e )      (e )      (e ) 

Genco

      24        21        (e )      (e )      (e )      (e )      (e )      (e ) 

Other(f)

      6        6        (e )      (e )      (e )      (e )      (e )      (e ) 

Ameren

                     66                        73                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Heating oil (in gallons)

                 

AMO

      (e )      (e )      (e )      (e )      (e )      (e )      62        80   

Genco

      (e )      (e )      (e )      (e )      31        43        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      9        12        (e )      (e ) 

Ameren

     (e )      (e )      (e )      (e )      40        55        62        80   

Natural gas (in mmbtu)

                 

AMO

      10        13        (e )      (e )      3        2        21        21   

AIC

      62        85        (e )      (e )      (e )      (e )      175        173   

Genco

      (e )      (e )      (e )      (e )      3        3        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      20        16        (e )      (e ) 

Ameren

     72        98        (e )      (e )      26        21        196        194   

Power (in megawatthours)

                 

AMO

      2        2        (e )      (e )      1        1        3        5   

AIC

      12        (e )      (e )      (e )      (e )      (e )      31        26   

Genco

      (e )      (e )      (e )      (e )      2        3        (e )      (e ) 

Other(f)

      65        61        21        2        51        57        (14 )      (13 ) 

Ameren

     79        63        21        2        54        61        20        18   

Uranium (pounds in thousands)

                 

AMO

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

Ameren

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

 

(a) Contracts through December 2014, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of June 30, 2011.
(b) Contracts through December 2013 for power as of June 30, 2011.
(c) Contracts through December 2013, December 2012, and May 2015 for heating oil, natural gas, and power, respectively, as of June 30, 2011.
(d) Contracts through December 2013, October 2016, May 2032 and December 2013 for heating oil, natural gas, power, and uranium, respectively, as of June 30, 2011.
(e) Not applicable.
(f) Includes AERG coal and heating oil, Marketing Company natural gas and power, and intercompany eliminations' for power.

Authoritative 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 our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

 

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and Ameren Illinois believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2011, and December 31, 2010:

 

      Balance Sheet Location   

Ameren(a)

      Ameren Missouri     Ameren Illinois     Genco  

2011:

          

Derivative assets designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative assets    $ 5       $ -      $ (b )    $ -   
  

Other assets

      2         -        -        -   
    

Total assets

    $ 7       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative liabilities    $ 3       $ (b )    $ -      $ -   
  

Other deferred credits and liabilities

      4         -        -        -   
    

Total liabilities

    $ 7       $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

          

Commodity contracts:

             

Heating oil

    MTM derivative assets    $ 49       $ 29      $ (b )    $ 15   
  

Other assets

      23         14        -        7   

Natural gas

    MTM derivative assets      5         -        (b )      1   
  

Other current assets

      -         -        2        -   
  

Other assets

      1         -        -        -   

Power

    MTM derivative assets      100         29        (b )      4   
  

Other current assets

      -         -        1        -   
  

Other assets

      85         1        68        -   
    

Total assets

    $ 263       $ 73      $ 71      $ 27   

Derivative liabilities not designated as hedging instruments(c)

          

Commodity contracts:

             

Heating oil

    MTM derivative liabilities    $ 4       $ (b )    $ -      $ 1   
  

Other current liabilities

      -         2        -        -   

Natural gas

    MTM derivative liabilities      75         (b )      60        2   
  

Other current liabilities

      -         10        -        -   
  

Other deferred credits and liabilities

      63         10        53        -   

Power

    MTM derivative liabilities      52         (b )      4        2   
  

MTM derivative liabilities - affiliates

      -         (b )      173        1   
  

Other current liabilities

      -         3        -        -   
  

Other deferred credits and liabilities

      14         1        96        -   

Uranium

    MTM derivative liabilities      1         (b )      -        -   
  

Other current liabilities

      -         1        -        -   
  

Other deferred credits and liabilities

      1         1        -        -   
    

Total liabilities

    $ 210       $ 28      $ 386      $ 6   

2010:

             

Derivative assets designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative assets    $ 3       $ -      $ (b )    $ -   
   Other assets      2         -        -        -   
    

Total assets

    $ 5       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative liabilities    $ 1       $ (b )    $ -      $ -   
    

Total liabilities

    $                           1       $ -      $ -      $                          -   
      Balance Sheet Location   

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

  

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Heating oil

    MTM derivative assets    $ 42      $ 24      $ (b )    $ 14   
   Other current assets      -        -        -        -   
   Other assets      22        13        -        7   

Natural gas

    MTM derivative assets      4        1        (b )      1   
   Other current assets      -        -        1        -   
   Other assets      1        -        1        -   

Power

    MTM derivative assets      78        8        (b )      11   
   Other current assets      -        -        2        -   
   Other assets      20        -        6        -   

Uranium

    MTM derivative assets      2        2        (b )      -   
     Other current assets      -        -        -        -   
     Total assets    $ 169      $ 48      $ 10      $ 33   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Heating oil

    MTM derivative liabilities    $ 12      $ (b )    $ -      $ 4   
   Other current liabilities      -        7        -        -   
   Other deferred credits and liabilities      1        -        -        -   

Natural gas

    MTM derivative liabilities      87        (b )      73        2   
   Other current liabilities      -        11        -        -   
   Other deferred credits and liabilities      84        13        70        -   

Power

    MTM derivative liabilities      61        (b )      9        3   
   MTM derivative liabilities - affiliates      (b )      (b )      172        5   
   Other current liabilities      -        6        -        -   
     Other deferred credits and liabilities      7        -        179        -   
     Total liabilities    $                        252      $ 37      $ 503      $                        14   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Balance sheet line item not applicable to registrant.
(c) Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of June 30, 2011, and December 31, 2010:

 

     

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

    

Other(a)

  

2011:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 3      $ -      $ -      $ -      $ 3   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

           

Heating oil derivative contracts(e)

      35        35        -        -        -   

Natural gas derivative contracts(f)

      (131 )      (20 )      (111 )      -        -   

Power derivative contracts(g)

      91        26        (204 )      -        269   

Uranium derivative contracts(h)

      (2 )      (2 )      -        -        -   

2010:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 8      $ -      $ -      $ -      $ 8   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

           

Heating oil derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (165 )      (24 )      (141 )      -        -   

Power derivative contracts(g)

      1        3        (352 )      -        350   

Uranium derivative contracts(h)

      2        2        -        -        -   

 

(a) Includes amounts for Marketing Company and intercompany eliminations.
(b) Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through December 2013 as of June 30, 2011. Current gains of $3 million and $8 million were recorded at Ameren as of June 30, 2011, and December 31, 2010, respectively.
(c) Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at June 30, 2011, and December 31, 2010, was less than $1 million and less than $1 million, respectively. The balance of the gain will be amortized by June 2012.
(d) Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco's April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at June 30, 2011, and December 31, 2010, was a loss of $9 million and $10 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e)

Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through December 2013 as of June 30, 2011. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and Ameren Illinois, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $69 million, $9 million, and $60 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(g) Represents net gains 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 2012 at Ameren Missouri, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $29 million, $28 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $5 million, $2 million, and $177 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(h) Represents net losses and gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of June 30, 2011. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri as of December 31, 2010, 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) 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) North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of June 30, 2011, and December 31, 2010, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

AMO

    $ -       $ 22       $ 2       $ 5       $ 39       $ 7       $ -       $ -       $ 75    

AIC

      -         -         29         -         2         -         -         -         31    

Genco

      -         12         1         1         3         -         4         -         21    

Other(b)

      333         7         7         10         47         217         1         68         690    

Ameren

     333         41         39         16         91         224         5         68         817    

2010:

                           

AMO

    $ -       $ 21       $ 1       $ 2       $ 5       $ 11       $ 1       $ -       $ 41    

AIC

      -         -         3         -         1         -         -         -         4    

Genco

      -         6         2         1         1         -         6         -         16    

Other(b)

      410         3         10         19         65         539         3         72         1,121    

Ameren

     410         30         16         22         72         550         10         72         1,182    

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

 

The following table presents the amount of cash collateral held from counterparties, as of June 30, 2011, and December 31, 2010, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

 

      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ -       $  -    

2010:

                           

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ 1       $ 1    

 

(a) Represents amounts held by Marketing Company. As of June 30, 2011, and December 31, 2010, Ameren registrant subsidiaries held no cash collateral.

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. As of June 30, 2011, other collateral consisted of letters of credit in the amount of $16 million, $1 million, $2 million and $13 million held by Ameren, Ameren Missouri, Ameren Illinois and Marketing Company, respectively. As of December 31, 2010, other collateral consisted of letters of credit in the amount of $28 million and $1 million held by Ameren and Ameren Illinois, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2011, and December 31, 2010:

 

      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

AMO

    $ -       $ 10       $ 1       $ 3       $ 33       $ 7       $ -       $ -       $ 54   

AIC

      -         -         27         -         -         -         -         -         27   

Genco

      -         4         1         -         1         -         3         -         9   

Other(b)

      317         4         6         5         35         205         -         67         639   

Ameren

     317         18         35         8         69         212         3         67         729   

2010:

                           

AMO

    $ -       $ 8       $ -       $ 1       $ 2       $ 10       $ -       $ -       $ 21   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         1         1         1         1         -         5         -         9   

Other(b)

      404         1         8         7         56         513         2         71         1,062   

Ameren

     404         10         11         9         59         523         7         71         1,094   

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies' credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of June 30, 2011, and December 31, 2010, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on June 30, 2011, or December 31, 2010, 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)		  

2011:

         

Ameren Missouri

    $ 113       $ 5         $                         67   

Ameren Illinois

      207         91         103   

Genco

      49         5         26   

Other(c)

      121         13         59   

Ameren

     490         114         255   

2010:

         

Ameren Missouri

    $ 105       $ 7         $                        93   

Ameren Illinois

      233         109         111   

Genco

      31         -         28   

Other(c)

      62         18         42   

Ameren

     431         134         274   

 

(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.
(c) Includes amounts for Marketing Company and Ameren (parent).

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three and six months ended June 30, 2011, and 2010, associated with derivative instruments designated as cash flow hedges. See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

 

     

Gain (Loss)

Recognized in
OCI(a)

    

Location of (Gain) Loss

Reclassified from

OCI into Income(b)

   

(Gain) Loss

Reclassified from

OCI into Income(b)

    

Location of Gain (Loss)

Recognized in Income(c)

   

Gain (Loss)

Recognized

in Income(c)

  

                             Three Months

 

                          

2011:

             

Ameren:(d)

             

Power

    $ (3 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ 3   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

             

Ameren:(d)

             

Power

    $ (16 )    Operating Revenues - Electric    $ (10 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

                             Six Months

 

                          

2011:

             

Ameren:(d)

             

Power

    $ (7 )    Operating Revenues - Electric    $ 2      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

             

Ameren:(d)

             

Power

    $ 10      Operating Revenues - Electric    $ (14 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

 

(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d) Includes amounts from Ameren registrant and nonregistrant subsidiaries.
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
(f) Less than $1 million.

 

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three and six months ended June 30, 2011, and 2010:

 

           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               Three Months          Six Months  
                  2011     2010           2011     2010  
Ameren(a)    Heating oil    Operating Expenses - Fuel    $ (9 )    $ (7 )       $ 10      $ (6 ) 
   Natural gas (generation)    Operating Expenses - Fuel      -        -           -        (1 ) 
     Power    Operating Revenues - Electric      (5 )      (11 )           (7 )      20   
         

Total

    $ (14 )    $ (18 )         $ 3      $ 13   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ -         $ (1 )    $ 1   
    

Power

    Operating Revenues - Electric      -        -             -        (1 ) 
          Total    $ -      $ -           $ (1 )    $ -   
Genco    Heating oil    Operating Expenses - Fuel    $ (8 )    $ (5 )       $ 7      $ (4 ) 
  

Natural gas (generation)

    Operating Expenses - Fuel      -        -           -        (1 ) 
    

Power

    Operating Revenues      (1 )      -             (1 )      1   
          Total    $ (9 )    $ (5 )         $ 6      $ (4 ) 

 

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

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and six months ended June 30, 2011, and 2010:

 

            Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets  
          Three Months          Six Months  
            2011     2010           2011     2010  

Ameren(a)

    Heating oil    $ (13 )    $ (9 )       $ 16      $ (8 ) 
  

Natural gas

      3        25           34        (81 ) 
  

Power

      88        33           90        23   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 75      $ 48           $ 136      $ (68 ) 

Ameren Missouri            

    Heating oil    $ (13 )    $ (9 )       $ 16      $ (8 ) 
  

Natural gas

      1        4           4        (11 ) 
  

Power

      23        (9 )         23        7   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 8      $ (15 )         $ 39      $ (14 ) 

Ameren Illinois

    Natural gas    $ 2      $ 21         $ 30      $ (70 ) 
    

Power

      121        150             148        17   
    

Total

    $ 123      $ 171           $ 178      $ (53 ) 

 

(a) Includes amounts for intercompany eliminations.

As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, Ameren Illinois entered into financial contracts with Marketing Company. These financial contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives that qualify for regulatory deferral by Ameren Illinois. Consequently, Ameren Illinois and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by Ameren Illinois and OCI by Marketing Company. In Ameren's consolidated financial statements, all financial statement effects of the derivative instruments entered into among affiliates were eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts. The following table presents the fair value of the financial contracts included on Ameren Illinois' balance sheet at June 30, 2011, and December 31, 2010:

 

            2011      2010  

AIC

    MTM derivative liabilities - affiliates    $ 173       $ 172   
     Other deferred credits and liabilities      95         178   
     Total    $             268       $             350   
Derivative Financial Instruments 

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, power, and uranium. Such price fluctuations may cause the following:

 

•  

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

 

•  

market values of coal, natural gas, and uranium inventories that differ from the cost of those commodities in inventory; and

 

•  

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross derivative volumes by commodity type as of June 30, 2011, and December 31, 2010:

 

      Quantity (in millions, except as indicated)  
Commodity   

NPNS

Contracts(a)

     Cash Flow
Hedges(b)		     Other
Derivatives(c)		     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2011     2010     2011     2010     2011     2010     2011     2010  

Coal (in tons)

                 

AMO

      36        46        (e )      (e )      (e )      (e )      (e )      (e ) 

Genco

      24        21        (e )      (e )      (e )      (e )      (e )      (e ) 

Other(f)

      6        6        (e )      (e )      (e )      (e )      (e )      (e ) 

Ameren

                     66                        73                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Heating oil (in gallons)

                 

AMO

      (e )      (e )      (e )      (e )      (e )      (e )      62        80   

Genco

      (e )      (e )      (e )      (e )      31        43        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      9        12        (e )      (e ) 

Ameren

     (e )      (e )      (e )      (e )      40        55        62        80   

Natural gas (in mmbtu)

                 

AMO

      10        13        (e )      (e )      3        2        21        21   

AIC

      62        85        (e )      (e )      (e )      (e )      175        173   

Genco

      (e )      (e )      (e )      (e )      3        3        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      20        16        (e )      (e ) 

Ameren

     72        98        (e )      (e )      26        21        196        194   

Power (in megawatthours)

                 

AMO

      2        2        (e )      (e )      1        1        3        5   

AIC

      12        (e )      (e )      (e )      (e )      (e )      31        26   

Genco

      (e )      (e )      (e )      (e )      2        3        (e )      (e ) 

Other(f)

      65        61        21        2        51        57        (14 )      (13 ) 

Ameren

     79        63        21        2        54        61        20        18   

Uranium (pounds in thousands)

                 

AMO

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

Ameren

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

 

(a) Contracts through December 2014, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of June 30, 2011.
(b) Contracts through December 2013 for power as of June 30, 2011.
(c) Contracts through December 2013, December 2012, and May 2015 for heating oil, natural gas, and power, respectively, as of June 30, 2011.
(d) Contracts through December 2013, October 2016, May 2032 and December 2013 for heating oil, natural gas, power, and uranium, respectively, as of June 30, 2011.
(e) Not applicable.
(f) Includes AERG coal and heating oil, Marketing Company natural gas and power, and intercompany eliminations' for power.

Authoritative 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 our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

 

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and Ameren Illinois believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2011, and December 31, 2010:

 

      Balance Sheet Location   

Ameren(a)

      Ameren Missouri     Ameren Illinois     Genco  

2011:

          

Derivative assets designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative assets    $ 5       $ -      $ (b )    $ -   
  

Other assets

      2         -        -        -   
    

Total assets

    $ 7       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative liabilities    $ 3       $ (b )    $ -      $ -   
  

Other deferred credits and liabilities

      4         -        -        -   
    

Total liabilities

    $ 7       $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

          

Commodity contracts:

             

Heating oil

    MTM derivative assets    $ 49       $ 29      $ (b )    $ 15   
  

Other assets

      23         14        -        7   

Natural gas

    MTM derivative assets      5         -        (b )      1   
  

Other current assets

      -         -        2        -   
  

Other assets

      1         -        -        -   

Power

    MTM derivative assets      100         29        (b )      4   
  

Other current assets

      -         -        1        -   
  

Other assets

      85         1        68        -   
    

Total assets

    $ 263       $ 73      $ 71      $ 27   

Derivative liabilities not designated as hedging instruments(c)

          

Commodity contracts:

             

Heating oil

    MTM derivative liabilities    $ 4       $ (b )    $ -      $ 1   
  

Other current liabilities

      -         2        -        -   

Natural gas

    MTM derivative liabilities      75         (b )      60        2   
  

Other current liabilities

      -         10        -        -   
  

Other deferred credits and liabilities

      63         10        53        -   

Power

    MTM derivative liabilities      52         (b )      4        2   
  

MTM derivative liabilities - affiliates

      -         (b )      173        1   
  

Other current liabilities

      -         3        -        -   
  

Other deferred credits and liabilities

      14         1        96        -   

Uranium

    MTM derivative liabilities      1         (b )      -        -   
  

Other current liabilities

      -         1        -        -   
  

Other deferred credits and liabilities

      1         1        -        -   
    

Total liabilities

    $ 210       $ 28      $ 386      $ 6   

2010:

             

Derivative assets designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative assets    $ 3       $ -      $ (b )    $ -   
   Other assets      2         -        -        -   
    

Total assets

    $ 5       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative liabilities    $ 1       $ (b )    $ -      $ -   
    

Total liabilities

    $                           1       $ -      $ -      $                          -   
      Balance Sheet Location   

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

  

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Heating oil

    MTM derivative assets    $ 42      $ 24      $ (b )    $ 14   
   Other current assets      -        -        -        -   
   Other assets      22        13        -        7   

Natural gas

    MTM derivative assets      4        1        (b )      1   
   Other current assets      -        -        1        -   
   Other assets      1        -        1        -   

Power

    MTM derivative assets      78        8        (b )      11   
   Other current assets      -        -        2        -   
   Other assets      20        -        6        -   

Uranium

    MTM derivative assets      2        2        (b )      -   
     Other current assets      -        -        -        -   
     Total assets    $ 169      $ 48      $ 10      $ 33   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Heating oil

    MTM derivative liabilities    $ 12      $ (b )    $ -      $ 4   
   Other current liabilities      -        7        -        -   
   Other deferred credits and liabilities      1        -        -        -   

Natural gas

    MTM derivative liabilities      87        (b )      73        2   
   Other current liabilities      -        11        -        -   
   Other deferred credits and liabilities      84        13        70        -   

Power

    MTM derivative liabilities      61        (b )      9        3   
   MTM derivative liabilities - affiliates      (b )      (b )      172        5   
   Other current liabilities      -        6        -        -   
     Other deferred credits and liabilities      7        -        179        -   
     Total liabilities    $                        252      $ 37      $ 503      $                        14   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Balance sheet line item not applicable to registrant.
(c) Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of June 30, 2011, and December 31, 2010:

 

     

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

    

Other(a)

  

2011:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 3      $ -      $ -      $ -      $ 3   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

           

Heating oil derivative contracts(e)

      35        35        -        -        -   

Natural gas derivative contracts(f)

      (131 )      (20 )      (111 )      -        -   

Power derivative contracts(g)

      91        26        (204 )      -        269   

Uranium derivative contracts(h)

      (2 )      (2 )      -        -        -   

2010:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 8      $ -      $ -      $ -      $ 8   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

           

Heating oil derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (165 )      (24 )      (141 )      -        -   

Power derivative contracts(g)

      1        3        (352 )      -        350   

Uranium derivative contracts(h)

      2        2        -        -        -   

 

(a) Includes amounts for Marketing Company and intercompany eliminations.
(b) Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through December 2013 as of June 30, 2011. Current gains of $3 million and $8 million were recorded at Ameren as of June 30, 2011, and December 31, 2010, respectively.
(c) Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at June 30, 2011, and December 31, 2010, was less than $1 million and less than $1 million, respectively. The balance of the gain will be amortized by June 2012.
(d) Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco's April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at June 30, 2011, and December 31, 2010, was a loss of $9 million and $10 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e)

Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through December 2013 as of June 30, 2011. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and Ameren Illinois, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $69 million, $9 million, and $60 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(g) Represents net gains 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 2012 at Ameren Missouri, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $29 million, $28 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $5 million, $2 million, and $177 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(h) Represents net losses and gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of June 30, 2011. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri as of December 31, 2010, 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) 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) North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of June 30, 2011, and December 31, 2010, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

AMO

    $ -       $ 22       $ 2       $ 5       $ 39       $ 7       $ -       $ -       $ 75    

AIC

      -         -         29         -         2         -         -         -         31    

Genco

      -         12         1         1         3         -         4         -         21    

Other(b)

      333         7         7         10         47         217         1         68         690    

Ameren

     333         41         39         16         91         224         5         68         817    

2010:

                           

AMO

    $ -       $ 21       $ 1       $ 2       $ 5       $ 11       $ 1       $ -       $ 41    

AIC

      -         -         3         -         1         -         -         -         4    

Genco

      -         6         2         1         1         -         6         -         16    

Other(b)

      410         3         10         19         65         539         3         72         1,121    

Ameren

     410         30         16         22         72         550         10         72         1,182    

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

 

The following table presents the amount of cash collateral held from counterparties, as of June 30, 2011, and December 31, 2010, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

 

      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ -       $  -    

2010:

                           

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ 1       $ 1    

 

(a) Represents amounts held by Marketing Company. As of June 30, 2011, and December 31, 2010, Ameren registrant subsidiaries held no cash collateral.

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. As of June 30, 2011, other collateral consisted of letters of credit in the amount of $16 million, $1 million, $2 million and $13 million held by Ameren, Ameren Missouri, Ameren Illinois and Marketing Company, respectively. As of December 31, 2010, other collateral consisted of letters of credit in the amount of $28 million and $1 million held by Ameren and Ameren Illinois, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2011, and December 31, 2010:

 

      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

AMO

    $ -       $ 10       $ 1       $ 3       $ 33       $ 7       $ -       $ -       $ 54   

AIC

      -         -         27         -         -         -         -         -         27   

Genco

      -         4         1         -         1         -         3         -         9   

Other(b)

      317         4         6         5         35         205         -         67         639   

Ameren

     317         18         35         8         69         212         3         67         729   

2010:

                           

AMO

    $ -       $ 8       $ -       $ 1       $ 2       $ 10       $ -       $ -       $ 21   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         1         1         1         1         -         5         -         9   

Other(b)

      404         1         8         7         56         513         2         71         1,062   

Ameren

     404         10         11         9         59         523         7         71         1,094   

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies' credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of June 30, 2011, and December 31, 2010, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on June 30, 2011, or December 31, 2010, 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)		  

2011:

         

Ameren Missouri

    $ 113       $ 5         $                         67   

Ameren Illinois

      207         91         103   

Genco

      49         5         26   

Other(c)

      121         13         59   

Ameren

     490         114         255   

2010:

         

Ameren Missouri

    $ 105       $ 7         $                        93   

Ameren Illinois

      233         109         111   

Genco

      31         -         28   

Other(c)

      62         18         42   

Ameren

     431         134         274   

 

(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.
(c) Includes amounts for Marketing Company and Ameren (parent).

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three and six months ended June 30, 2011, and 2010, associated with derivative instruments designated as cash flow hedges. See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

 

     

Gain (Loss)

Recognized in
OCI(a)

    

Location of (Gain) Loss

Reclassified from

OCI into Income(b)

   

(Gain) Loss

Reclassified from

OCI into Income(b)

    

Location of Gain (Loss)

Recognized in Income(c)

   

Gain (Loss)

Recognized

in Income(c)

  

                             Three Months

 

                          

2011:

             

Ameren:(d)

             

Power

    $ (3 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ 3   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

             

Ameren:(d)

             

Power

    $ (16 )    Operating Revenues - Electric    $ (10 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

                             Six Months

 

                          

2011:

             

Ameren:(d)

             

Power

    $ (7 )    Operating Revenues - Electric    $ 2      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

             

Ameren:(d)

             

Power

    $ 10      Operating Revenues - Electric    $ (14 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

 

(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d) Includes amounts from Ameren registrant and nonregistrant subsidiaries.
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
(f) Less than $1 million.

 

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three and six months ended June 30, 2011, and 2010:

 

           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               Three Months          Six Months  
                  2011     2010           2011     2010  
Ameren(a)    Heating oil    Operating Expenses - Fuel    $ (9 )    $ (7 )       $ 10      $ (6 ) 
   Natural gas (generation)    Operating Expenses - Fuel      -        -           -        (1 ) 
     Power    Operating Revenues - Electric      (5 )      (11 )           (7 )      20   
         

Total

    $ (14 )    $ (18 )         $ 3      $ 13   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ -         $ (1 )    $ 1   
    

Power

    Operating Revenues - Electric      -        -             -        (1 ) 
          Total    $ -      $ -           $ (1 )    $ -   
Genco    Heating oil    Operating Expenses - Fuel    $ (8 )    $ (5 )       $ 7      $ (4 ) 
  

Natural gas (generation)

    Operating Expenses - Fuel      -        -           -        (1 ) 
    

Power

    Operating Revenues      (1 )      -             (1 )      1   
          Total    $ (9 )    $ (5 )         $ 6      $ (4 ) 

 

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

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and six months ended June 30, 2011, and 2010:

 

            Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets  
          Three Months          Six Months  
            2011     2010           2011     2010  

Ameren(a)

    Heating oil    $ (13 )    $ (9 )       $ 16      $ (8 ) 
  

Natural gas

      3        25           34        (81 ) 
  

Power

      88        33           90        23   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 75      $ 48           $ 136      $ (68 ) 

Ameren Missouri            

    Heating oil    $ (13 )    $ (9 )       $ 16      $ (8 ) 
  

Natural gas

      1        4           4        (11 ) 
  

Power

      23        (9 )         23        7   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 8      $ (15 )         $ 39      $ (14 ) 

Ameren Illinois

    Natural gas    $ 2      $ 21         $ 30      $ (70 ) 
    

Power

      121        150             148        17   
    

Total

    $ 123      $ 171           $ 178      $ (53 ) 

 

(a) Includes amounts for intercompany eliminations.

As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, Ameren Illinois entered into financial contracts with Marketing Company. These financial contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives that qualify for regulatory deferral by Ameren Illinois. Consequently, Ameren Illinois and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by Ameren Illinois and OCI by Marketing Company. In Ameren's consolidated financial statements, all financial statement effects of the derivative instruments entered into among affiliates were eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts. The following table presents the fair value of the financial contracts included on Ameren Illinois' balance sheet at June 30, 2011, and December 31, 2010:

 

            2011      2010  

AIC

    MTM derivative liabilities - affiliates    $ 173       $ 172   
     Other deferred credits and liabilities      95         178   
     Total    $             268       $             350   
Derivative Financial Instruments 

NOTE 6 - DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, coal, diesel, power, and uranium. Such price fluctuations may cause the following:

 

•  

an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;

 

•  

market values of coal, natural gas, and uranium inventories that differ from the cost of those commodities in inventory; and

 

•  

actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements. Contracts we enter into as part of our risk management program may be settled financially, settled by physical delivery, or net settled with the counterparty.

The following table presents open gross derivative volumes by commodity type as of June 30, 2011, and December 31, 2010:

 

      Quantity (in millions, except as indicated)  
Commodity   

NPNS

Contracts(a)

     Cash Flow
Hedges(b)		     Other
Derivatives(c)		     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2011     2010     2011     2010     2011     2010     2011     2010  

Coal (in tons)

                 

AMO

      36        46        (e )      (e )      (e )      (e )      (e )      (e ) 

Genco

      24        21        (e )      (e )      (e )      (e )      (e )      (e ) 

Other(f)

      6        6        (e )      (e )      (e )      (e )      (e )      (e ) 

Ameren

                     66                        73                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Heating oil (in gallons)

                 

AMO

      (e )      (e )      (e )      (e )      (e )      (e )      62        80   

Genco

      (e )      (e )      (e )      (e )      31        43        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      9        12        (e )      (e ) 

Ameren

     (e )      (e )      (e )      (e )      40        55        62        80   

Natural gas (in mmbtu)

                 

AMO

      10        13        (e )      (e )      3        2        21        21   

AIC

      62        85        (e )      (e )      (e )      (e )      175        173   

Genco

      (e )      (e )      (e )      (e )      3        3        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      20        16        (e )      (e ) 

Ameren

     72        98        (e )      (e )      26        21        196        194   

Power (in megawatthours)

                 

AMO

      2        2        (e )      (e )      1        1        3        5   

AIC

      12        (e )      (e )      (e )      (e )      (e )      31        26   

Genco

      (e )      (e )      (e )      (e )      2        3        (e )      (e ) 

Other(f)

      65        61        21        2        51        57        (14 )      (13 ) 

Ameren

     79        63        21        2        54        61        20        18   

Uranium (pounds in thousands)

                 

AMO

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

Ameren

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

 

(a) Contracts through December 2014, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of June 30, 2011.
(b) Contracts through December 2013 for power as of June 30, 2011.
(c) Contracts through December 2013, December 2012, and May 2015 for heating oil, natural gas, and power, respectively, as of June 30, 2011.
(d) Contracts through December 2013, October 2016, May 2032 and December 2013 for heating oil, natural gas, power, and uranium, respectively, as of June 30, 2011.
(e) Not applicable.
(f) Includes AERG coal and heating oil, Marketing Company natural gas and power, and intercompany eliminations' for power.

Authoritative 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 our methods of assessing the fair value of derivative instruments. Many of our physical contracts, such as our coal and purchased power contracts, qualify for the NPNS exception to derivative accounting rules. The revenue or expense on NPNS contracts is recognized at the contract price upon physical delivery.

If we determine that a contract meets the definition of a derivative and is not eligible for the NPNS exception, we review the contract to determine if it qualifies for hedge accounting. We also consider whether gains or losses resulting from such derivatives qualify for regulatory deferral. Contracts that qualify for cash flow hedge accounting are recorded at fair value with changes in fair value charged or credited to accumulated OCI in the period in which the change occurs, to the extent the hedge is effective. To the extent the hedge is ineffective, the related changes in fair value are charged or credited to the statement of income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income.

 

Derivative contracts that qualify for regulatory deferral are recorded at fair value, with changes in fair value charged or credited to regulatory assets or regulatory liabilities in the period in which the change occurs. Ameren Missouri and Ameren Illinois believe derivative gains and losses deferred as regulatory assets and regulatory liabilities are probable of recovery or refund through future rates charged to customers. Regulatory assets and regulatory liabilities are amortized to operating income as related losses and gains are reflected in rates charged to customers. Therefore, gains and losses on these derivatives have no effect on operating income.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for the NPNS exception, hedge accounting, or regulatory deferral accounting. Such contracts are recorded at fair value, with changes in fair value charged or credited to the statement of income in the period in which the change occurs.

The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2011, and December 31, 2010:

 

      Balance Sheet Location   

Ameren(a)

      Ameren Missouri     Ameren Illinois     Genco  

2011:

          

Derivative assets designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative assets    $ 5       $ -      $ (b )    $ -   
  

Other assets

      2         -        -        -   
    

Total assets

    $ 7       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative liabilities    $ 3       $ (b )    $ -      $ -   
  

Other deferred credits and liabilities

      4         -        -        -   
    

Total liabilities

    $ 7       $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

          

Commodity contracts:

             

Heating oil

    MTM derivative assets    $ 49       $ 29      $ (b )    $ 15   
  

Other assets

      23         14        -        7   

Natural gas

    MTM derivative assets      5         -        (b )      1   
  

Other current assets

      -         -        2        -   
  

Other assets

      1         -        -        -   

Power

    MTM derivative assets      100         29        (b )      4   
  

Other current assets

      -         -        1        -   
  

Other assets

      85         1        68        -   
    

Total assets

    $ 263       $ 73      $ 71      $ 27   

Derivative liabilities not designated as hedging instruments(c)

          

Commodity contracts:

             

Heating oil

    MTM derivative liabilities    $ 4       $ (b )    $ -      $ 1   
  

Other current liabilities

      -         2        -        -   

Natural gas

    MTM derivative liabilities      75         (b )      60        2   
  

Other current liabilities

      -         10        -        -   
  

Other deferred credits and liabilities

      63         10        53        -   

Power

    MTM derivative liabilities      52         (b )      4        2   
  

MTM derivative liabilities - affiliates

      -         (b )      173        1   
  

Other current liabilities

      -         3        -        -   
  

Other deferred credits and liabilities

      14         1        96        -   

Uranium

    MTM derivative liabilities      1         (b )      -        -   
  

Other current liabilities

      -         1        -        -   
  

Other deferred credits and liabilities

      1         1        -        -   
    

Total liabilities

    $ 210       $ 28      $ 386      $ 6   

2010:

             

Derivative assets designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative assets    $ 3       $ -      $ (b )    $ -   
   Other assets      2         -        -        -   
    

Total assets

    $ 5       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

          

Commodity contracts:

             

Power

    MTM derivative liabilities    $ 1       $ (b )    $ -      $ -   
    

Total liabilities

    $                           1       $ -      $ -      $                          -   
      Balance Sheet Location   

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

  

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Heating oil

    MTM derivative assets    $ 42      $ 24      $ (b )    $ 14   
   Other current assets      -        -        -        -   
   Other assets      22        13        -        7   

Natural gas

    MTM derivative assets      4        1        (b )      1   
   Other current assets      -        -        1        -   
   Other assets      1        -        1        -   

Power

    MTM derivative assets      78        8        (b )      11   
   Other current assets      -        -        2        -   
   Other assets      20        -        6        -   

Uranium

    MTM derivative assets      2        2        (b )      -   
     Other current assets      -        -        -        -   
     Total assets    $ 169      $ 48      $ 10      $ 33   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Heating oil

    MTM derivative liabilities    $ 12      $ (b )    $ -      $ 4   
   Other current liabilities      -        7        -        -   
   Other deferred credits and liabilities      1        -        -        -   

Natural gas

    MTM derivative liabilities      87        (b )      73        2   
   Other current liabilities      -        11        -        -   
   Other deferred credits and liabilities      84        13        70        -   

Power

    MTM derivative liabilities      61        (b )      9        3   
   MTM derivative liabilities - affiliates      (b )      (b )      172        5   
   Other current liabilities      -        6        -        -   
     Other deferred credits and liabilities      7        -        179        -   
     Total liabilities    $                        252      $ 37      $ 503      $                        14   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Balance sheet line item not applicable to registrant.
(c) Includes derivatives subject to regulatory deferral.

The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments in accumulated OCI and regulatory assets or regulatory liabilities as of June 30, 2011, and December 31, 2010:

 

     

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

    

Other(a)

  

2011:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 3      $ -      $ -      $ -      $ 3   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

           

Heating oil derivative contracts(e)

      35        35        -        -        -   

Natural gas derivative contracts(f)

      (131 )      (20 )      (111 )      -        -   

Power derivative contracts(g)

      91        26        (204 )      -        269   

Uranium derivative contracts(h)

      (2 )      (2 )      -        -        -   

2010:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 8      $ -      $ -      $ -      $ 8   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

           

Heating oil derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (165 )      (24 )      (141 )      -        -   

Power derivative contracts(g)

      1        3        (352 )      -        350   

Uranium derivative contracts(h)

      2        2        -        -        -   

 

(a) Includes amounts for Marketing Company and intercompany eliminations.
(b) Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through December 2013 as of June 30, 2011. Current gains of $3 million and $8 million were recorded at Ameren as of June 30, 2011, and December 31, 2010, respectively.
(c) Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at June 30, 2011, and December 31, 2010, was less than $1 million and less than $1 million, respectively. The balance of the gain will be amortized by June 2012.
(d) Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco's April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at June 30, 2011, and December 31, 2010, was a loss of $9 million and $10 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e)

Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through December 2013 as of June 30, 2011. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and Ameren Illinois, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $69 million, $9 million, and $60 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(g) Represents net gains 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 2012 at Ameren Missouri, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $29 million, $28 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $5 million, $2 million, and $177 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(h) Represents net losses and gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of June 30, 2011. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri as of December 31, 2010, 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) 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) North American Energy Standards Board Inc. Agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

Concentrations of Credit Risk

In determining our concentrations of credit risk related to derivative instruments, we review our individual counterparties and categorize each counterparty into one of eight groupings according to the primary business in which each engages. The following table presents the maximum exposure, as of June 30, 2011, and December 31, 2010, if counterparty groups were to completely fail to perform on contracts by grouping. The maximum exposure is based on the gross fair value of financial instruments, including NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.

 

      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

AMO

    $ -       $ 22       $ 2       $ 5       $ 39       $ 7       $ -       $ -       $ 75    

AIC

      -         -         29         -         2         -         -         -         31    

Genco

      -         12         1         1         3         -         4         -         21    

Other(b)

      333         7         7         10         47         217         1         68         690    

Ameren

     333         41         39         16         91         224         5         68         817    

2010:

                           

AMO

    $ -       $ 21       $ 1       $ 2       $ 5       $ 11       $ 1       $ -       $ 41    

AIC

      -         -         3         -         1         -         -         -         4    

Genco

      -         6         2         1         1         -         6         -         16    

Other(b)

      410         3         10         19         65         539         3         72         1,121    

Ameren

     410         30         16         22         72         550         10         72         1,182    

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

 

The following table presents the amount of cash collateral held from counterparties, as of June 30, 2011, and December 31, 2010, based on the contractual rights under the agreements to seek collateral and the maximum exposure as calculated under the individual master trading and netting agreements:

 

      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ -       $  -    

2010:

                           

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ 1       $ 1    

 

(a) Represents amounts held by Marketing Company. As of June 30, 2011, and December 31, 2010, Ameren registrant subsidiaries held no cash collateral.

The potential loss on counterparty exposures is reduced by all collateral held and the application of master trading and netting agreements. Collateral includes both cash collateral and other collateral held. As of June 30, 2011, other collateral consisted of letters of credit in the amount of $16 million, $1 million, $2 million and $13 million held by Ameren, Ameren Missouri, Ameren Illinois and Marketing Company, respectively. As of December 31, 2010, other collateral consisted of letters of credit in the amount of $28 million and $1 million held by Ameren and Ameren Illinois, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2011, and December 31, 2010:

 

      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                           

AMO

    $ -       $ 10       $ 1       $ 3       $ 33       $ 7       $ -       $ -       $ 54   

AIC

      -         -         27         -         -         -         -         -         27   

Genco

      -         4         1         -         1         -         3         -         9   

Other(b)

      317         4         6         5         35         205         -         67         639   

Ameren

     317         18         35         8         69         212         3         67         729   

2010:

                           

AMO

    $ -       $ 8       $ -       $ 1       $ 2       $ 10       $ -       $ -       $ 21   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         1         1         1         1         -         5         -         9   

Other(b)

      404         1         8         7         56         513         2         71         1,062   

Ameren

     404         10         11         9         59         523         7         71         1,094   

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

Derivative Instruments with Credit Risk-Related Contingent Features

Our commodity contracts contain collateral provisions tied to the Ameren Companies' credit ratings. If we were to experience an adverse change in our credit ratings, or if a counterparty with reasonable grounds for uncertainty regarding performance of an obligation requested adequate assurance of performance, additional collateral postings might be required. The following table presents, as of June 30, 2011, and December 31, 2010, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on June 30, 2011, or December 31, 2010, 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)		  

2011:

         

Ameren Missouri

    $ 113       $ 5         $                         67   

Ameren Illinois

      207         91         103   

Genco

      49         5         26   

Other(c)

      121         13         59   

Ameren

     490         114         255   

2010:

         

Ameren Missouri

    $ 105       $ 7         $                        93   

Ameren Illinois

      233         109         111   

Genco

      31         -         28   

Other(c)

      62         18         42   

Ameren

     431         134         274   

 

(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.
(c) Includes amounts for Marketing Company and Ameren (parent).

Cash Flow Hedges

The following table presents the pretax net gain or loss for the three and six months ended June 30, 2011, and 2010, associated with derivative instruments designated as cash flow hedges. See Note 11 - Other Comprehensive Income for additional information regarding changes in OCI.

 

     

Gain (Loss)

Recognized in
OCI(a)

    

Location of (Gain) Loss

Reclassified from

OCI into Income(b)

   

(Gain) Loss

Reclassified from

OCI into Income(b)

    

Location of Gain (Loss)

Recognized in Income(c)

   

Gain (Loss)

Recognized

in Income(c)

  

                             Three Months

 

                          

2011:

             

Ameren:(d)

             

Power

    $ (3 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ 3   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

             

Ameren:(d)

             

Power

    $ (16 )    Operating Revenues - Electric    $ (10 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

                             Six Months

 

                          

2011:

             

Ameren:(d)

             

Power

    $ (7 )    Operating Revenues - Electric    $ 2      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

             

Ameren:(d)

             

Power

    $ 10      Operating Revenues - Electric    $ (14 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

 

(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d) Includes amounts from Ameren registrant and nonregistrant subsidiaries.
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
(f) Less than $1 million.

 

Other Derivatives

The following table represents the net change in market value for derivatives not designated as hedging instruments for the three and six months ended June 30, 2011, and 2010:

 

           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               Three Months          Six Months  
                  2011     2010           2011     2010  
Ameren(a)    Heating oil    Operating Expenses - Fuel    $ (9 )    $ (7 )       $ 10      $ (6 ) 
   Natural gas (generation)    Operating Expenses - Fuel      -        -           -        (1 ) 
     Power    Operating Revenues - Electric      (5 )      (11 )           (7 )      20   
         

Total

    $ (14 )    $ (18 )         $ 3      $ 13   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ -         $ (1 )    $ 1   
    

Power

    Operating Revenues - Electric      -        -             -        (1 ) 
          Total    $ -      $ -           $ (1 )    $ -   
Genco    Heating oil    Operating Expenses - Fuel    $ (8 )    $ (5 )       $ 7      $ (4 ) 
  

Natural gas (generation)

    Operating Expenses - Fuel      -        -           -        (1 ) 
    

Power

    Operating Revenues      (1 )      -             (1 )      1   
          Total    $ (9 )    $ (5 )         $ 6      $ (4 ) 

 

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

Derivatives that Qualify for Regulatory Deferral

The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and six months ended June 30, 2011, and 2010:

 

            Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets  
          Three Months          Six Months  
            2011     2010           2011     2010  

Ameren(a)

    Heating oil    $ (13 )    $ (9 )       $ 16      $ (8 ) 
  

Natural gas

      3        25           34        (81 ) 
  

Power

      88        33           90        23   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 75      $ 48           $ 136      $ (68 ) 

Ameren Missouri            

    Heating oil    $ (13 )    $ (9 )       $ 16      $ (8 ) 
  

Natural gas

      1        4           4        (11 ) 
  

Power

      23        (9 )         23        7   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 8      $ (15 )         $ 39      $ (14 ) 

Ameren Illinois

    Natural gas    $ 2      $ 21         $ 30      $ (70 ) 
    

Power

      121        150             148        17   
    

Total

    $ 123      $ 171           $ 178      $ (53 ) 

 

(a) Includes amounts for intercompany eliminations.

As part of the 2007 Illinois Electric Settlement Agreement and subsequent Illinois power procurement processes, Ameren Illinois entered into financial contracts with Marketing Company. These financial contracts are derivative instruments. They are accounted for as cash flow hedges by Marketing Company and as derivatives that qualify for regulatory deferral by Ameren Illinois. Consequently, Ameren Illinois and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities by Ameren Illinois and OCI by Marketing Company. In Ameren's consolidated financial statements, all financial statement effects of the derivative instruments entered into among affiliates were eliminated. See Note 14 - Related Party Transactions under Part II, Item 8 of the Form 10-K for additional information on these financial contracts. The following table presents the fair value of the financial contracts included on Ameren Illinois' balance sheet at June 30, 2011, and December 31, 2010:

 

            2011      2010  

AIC

    MTM derivative liabilities - affiliates    $ 173       $ 172   
     Other deferred credits and liabilities      95         178   
     Total    $             268       $             350   
Fair Value Measurements
6 Months Ended
Jun. 30, 2011
Fair Value Measurements
Text Block 
Ameren Illinois [Member]
 
Fair Value Measurements
Text Block 
Ameren Energy Generating Company [Member]
 
Fair Value Measurements
Text Block 
Union Electric Company [Member]
 
Fair Value Measurements
Text Block 
Fair Value Measurements 

NOTE 7 - FAIR VALUE MEASUREMENTS

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.

See Note 8 - Fair Value Measurements under Part II, Item 8, of the Form 10-K for additional information of the definition of fair value and the fair value hierarchy.

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded losses totaling less than $1 million in the first six months of 2011 and gains totaling less than $1 million in the first six months of 2010 related to valuation adjustments for counterparty default risk. At June 30, 2011, the counterparty default risk valuation adjustment related to net derivative assets totaled $1 million and less than $1 million for Ameren and Genco, respectively. The counterparty default risk valuation adjustment related to net derivative liabilities totaled less than $1 million and $11 million for Ameren Missouri and Ameren Illinois, respectively. At December 31, 2010, the counterparty default risk valuation adjustment related to derivative contracts totaled $2 million, less than $1 million, $21 million, and less than $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of June 30, 2011:

 

          

Quoted Prices in

Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

          Total      

Assets:

              

Ameren(a)             

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 72       $ 72   
 

Natural gas

      3         -         3         6   
 

Power

      -         18         174         192   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AMO

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         43         43   
 

Power

      -         2         28         30   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AIC

  

Derivative assets - commodity contracts(b):

            
 

Natural gas

      -         -         2         2   
   

Power

      -         -         69         69   

Genco

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         22         22   
 

Natural gas

      1         -         -         1   
   

Power

      -         -         4         4   

Liabilities:

              

Ameren(a)

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 4       $ 4   
 

Natural gas

      18         -         120         138   
 

Power

      -         16         57         73   
   

Uranium

      -         -         2         2   

AMO

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         2         2   
 

Natural gas

      9         -         11         20   
 

Power

      -         1         3         4   
   

Uranium

      -         -         2         2   

AIC

  

Derivative liabilities - commodity contracts(b):

            
 

Natural gas

      5         -         108         113   
   

Power

      -         -         273         273   

Genco

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         1         1   
 

Natural gas

      2         -         -         2   
   

Power

      -         -         3         3   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 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, 2010:

 

           

Quoted Prices in
Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

              Total           

Assets:

               

Ameren(a)

    Derivative assets - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 64       $ 64    
  

Natural gas

      3         -         2         5    
  

Power

      -         17         86         103    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AMO

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         37         37    
  

Natural gas

      -         -         1         1    
  

Power

      -         3         5         8    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AIC

    Derivative assets - commodity contracts(b):            
  

Natural gas

      -         -         2         2    
    

Power

      -         -         8         8    

Genco

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         21         21    
  

Natural gas

      1         -         -         1    
    

Power

      -         -         11         11    

Liabilities:

               

Ameren(a)

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 13       $ 13    
  

Natural gas

      21         -         150         171    
    

Power

      -         19         50         69    

AMO

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         7         7    
  

Natural gas

      9         -         15         24    
    

Power

      -         3         3         6    

AIC

    Derivative liabilities - commodity contracts(b):            
  

Natural gas

      7         -         136         143    
    

Power

      -         -         360         360    

Genco

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         4         4    
  

Natural gas

      2         -         -         2    
    

Power

      -         -         8         8    

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 million of receivables, payables, and accrued income, net.

 

In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance required disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also required information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. This guidance was effective for us as of January 1, 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which became effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2011:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2011

      $ 96         $ 57         $         (a )       $ 29         $ 10   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (5 )         -           (a )         (3 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (14 )         (9 )         (a )         (3 )         (2 ) 

Purchases

        1           1           (a )         -           -   

Settlements

        (15 )         (8 )         (a )         (5 )         (2 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (14 )       $ (8 )       $ (a )       $ (4 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2011

      $ (120 )       $ (12 )       $ (108 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (20 )         (1 )         (19 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (20 )         (1 )         (19 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        22           2           20           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (18 )       $ (1 )       $ (17 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2011

      $ 31         $ 2         $ (325 )       $ 3         $ 351   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (15 )         -           -           (1 )         (14 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        66           (1 )         77           (a )         (10 ) 

Total realized and unrealized gains (losses)

        56           (1 )         77           (1 )         (19 ) 

Purchases

        50           29           -           -           21   

Sales

        (7 )         -           -           -           (7 ) 

Settlements

        (16 )         (6 )         44           (1 )         (53 ) 

Transfers into Level 3

        1           -           -           -           1   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ (1 )       $ 68         $ (1 )       $ (7 ) 

Uranium:

                         

Beginning balance at April 1, 2011

      $ 1         $ 1         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (3 )         (3 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (3 )         (3 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2010:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2010

      $ 54         $ 31         $         (a )       $ 18         $ 5   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (8 )         -           (a )         (6 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (17 )         (9 )         (a )         (6 )         (2 ) 

Purchases

        33           17           (a )         11           5   

Settlements

        (41 )         (23 )         (a )         (13 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (16 )       $ (9 )       $ (a )       $ (5 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2010

      $ (162 )       $ (18 )       $ (144 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (6 )         (1 )         (5 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (6 )         (1 )         (5 )         -           -   

Purchases

        -           -           -           -           -   

Settlements

        30           4           26           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (6 )       $ (1 )       $ (5 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2010

      $ 37         $ 5         $ (554 )       $ 3         $ 583   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       6           -           -           -           6   

Included in OCI

        (18 )         -           -           -           (18 ) 

Included in regulatory assets/liabilities

        29           1           98           (a )         (70 ) 

Total realized and unrealized gains (losses)

        17           1           98           -           (82 ) 

Purchases

        25           5           17           (2 )         5   

Sales

        2           -           -           3           (1 ) 

Settlements

        (19 )         (6 )         33           (1 )         (45 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (7 )         -           -           -           (7 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (5 )       $ (3 )       $ 67         $ -         $ (69 ) 

Uranium:

                         

Beginning balance at April 1, 2010

      $ (3 )       $ (3 )       $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (1 )         (1 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (1 )         (1 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ -         $ -         $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2011:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2011

      $ 51         $ 30         $         (a )       $ 17         $ 4   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        17           -           (a )         12           5   

Included in regulatory assets/liabilities

        22           22           (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        39           22           (a )         12           5   

Purchases

        2           2           (a )         -           -   

Settlements

        (24 )         (13 )         (a )         (8 )         (3 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 30         $ 18         $ (a )       $ 9         $ 3   

Natural gas:

                         

Beginning balance at January 1, 2011

      $ (148 )       $ (14 )       $ (134 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (13 )         (1 )         (12 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (13 )         (1 )         (12 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        43           4           39           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 9         $ 1         $ 8         $ -         $ -   

Power:

                         

Beginning balance at January 1, 2011

      $ 36         $ 2         $ (352 )       $ 3         $ 383   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (18 )         -           -           (1 )         (17 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        64           6           47           (a )         11   

Total realized and unrealized gains (losses)

        51           6           47           (1 )         (1 ) 

Purchases

        59           29           -           -           30   

Sales

        (16 )         -           -           -           (16 ) 

Settlements

        (16 )         (12 )         101           (1 )         (104 ) 

Transfers into Level 3

        1           (1 )         -           -           2   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ -         $ 64         $ (1 )       $ (4 ) 

Uranium:

                         

Beginning balance at January 1, 2011

      $ 2         $ 2         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (4 )         (4 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (4 )         (4 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2010:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2010

      $ 60         $ 32         $         (a )       $ 21         $ 7   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (10 )         -           (a )         (8 )         (2 ) 

Included in regulatory assets/liabilities

        (11 )         (11 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (21 )         (11 )         (a )         (8 )         (2 ) 

Purchases

        32           18           (a )         11           3   

Settlements

        (42 )         (23 )         (a )         (14 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (18 )       $ (10 )       $ (a )       $ (6 )       $ (2 ) 

Natural gas:

                         

Beginning balance at January 1, 2010

      $ (67 )       $ (6 )       $ (61 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (109 )         (14 )         (95 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (109 )         (14 )         (95 )         -           -   

Purchases

        (4 )         -           (4 )         -           -   

Settlements

        42           5           37           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (81 )       $ (10 )       $ (71 )       $ -         $ -   

Power:

                         

Beginning balance at January 1, 2010

      $ 38         $ (1 )       $ (422 )       $ 1         $ 460   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       24           -           -           2           22   

Included in OCI

        6           -           -           -           6   

Included in regulatory assets/liabilities

        7           13           (69 )         (a )         63   

Total realized and unrealized gains (losses)

        37           13           (69 )         2           91   

Purchases

        38           4           17           (4 )         21   

Sales

        (5 )         1           -           5           (11 ) 

Settlements

        (29 )         (9 )         68           (1 )         (87 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (24 )         (3 )         -           -           (21 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (7 )       $ 1         $ (79 )       $ 1         $ 70   

Uranium:

                         

Beginning balance at January 1, 2010

      $ (2 )       $ (2 )       $ (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (2 )         (2 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (2 )         (2 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (1 )       $ (1 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

Transfers out of Level 3 represent 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 into Level 3 represent existing assets and liabilities that were previously classified as a higher level but were recategorized to Level 3 because the lowest significant input became unobservable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable in active markets compared with previous periods for the quarters ended June 30, 2011, and 2010. Any reclassifications are reported at the fair value measurement reported at the beginning of the period in which the changes occur. For the three and six months ended June 30, 2011, and 2010, there were no transfers into or out of Level 1.

The Ameren Companies' carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. 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.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at June 30, 2011, and December 31, 2010:

 

      June 30, 2011      December 31, 2010  
     

Carrying

Amount

     

Fair

Value

     

Carrying

Amount

     

Fair

Value

  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,859       $    7,666       $ 7,008       $    7,661   

Preferred stock

      142         102         142         102   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,954       $ 4,378       $ 3,954       $ 4,281   

Preferred stock

      80         61         80         62   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,956       $ 1,807       $ 2,067   

Preferred stock

      62         41         62         40   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 843       $ 824       $ 826   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Preferred stock not subject to mandatory redemption of the Ameren subsidiaries along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.
Fair Value Measurements 

NOTE 7 - FAIR VALUE MEASUREMENTS

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.

See Note 8 - Fair Value Measurements under Part II, Item 8, of the Form 10-K for additional information of the definition of fair value and the fair value hierarchy.

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded losses totaling less than $1 million in the first six months of 2011 and gains totaling less than $1 million in the first six months of 2010 related to valuation adjustments for counterparty default risk. At June 30, 2011, the counterparty default risk valuation adjustment related to net derivative assets totaled $1 million and less than $1 million for Ameren and Genco, respectively. The counterparty default risk valuation adjustment related to net derivative liabilities totaled less than $1 million and $11 million for Ameren Missouri and Ameren Illinois, respectively. At December 31, 2010, the counterparty default risk valuation adjustment related to derivative contracts totaled $2 million, less than $1 million, $21 million, and less than $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of June 30, 2011:

 

          

Quoted Prices in

Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

          Total      

Assets:

              

Ameren(a)             

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 72       $ 72   
 

Natural gas

      3         -         3         6   
 

Power

      -         18         174         192   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AMO

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         43         43   
 

Power

      -         2         28         30   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AIC

  

Derivative assets - commodity contracts(b):

            
 

Natural gas

      -         -         2         2   
   

Power

      -         -         69         69   

Genco

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         22         22   
 

Natural gas

      1         -         -         1   
   

Power

      -         -         4         4   

Liabilities:

              

Ameren(a)

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 4       $ 4   
 

Natural gas

      18         -         120         138   
 

Power

      -         16         57         73   
   

Uranium

      -         -         2         2   

AMO

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         2         2   
 

Natural gas

      9         -         11         20   
 

Power

      -         1         3         4   
   

Uranium

      -         -         2         2   

AIC

  

Derivative liabilities - commodity contracts(b):

            
 

Natural gas

      5         -         108         113   
   

Power

      -         -         273         273   

Genco

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         1         1   
 

Natural gas

      2         -         -         2   
   

Power

      -         -         3         3   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 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, 2010:

 

           

Quoted Prices in
Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

              Total           

Assets:

               

Ameren(a)

    Derivative assets - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 64       $ 64    
  

Natural gas

      3         -         2         5    
  

Power

      -         17         86         103    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AMO

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         37         37    
  

Natural gas

      -         -         1         1    
  

Power

      -         3         5         8    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AIC

    Derivative assets - commodity contracts(b):            
  

Natural gas

      -         -         2         2    
    

Power

      -         -         8         8    

Genco

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         21         21    
  

Natural gas

      1         -         -         1    
    

Power

      -         -         11         11    

Liabilities:

               

Ameren(a)

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 13       $ 13    
  

Natural gas

      21         -         150         171    
    

Power

      -         19         50         69    

AMO

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         7         7    
  

Natural gas

      9         -         15         24    
    

Power

      -         3         3         6    

AIC

    Derivative liabilities - commodity contracts(b):            
  

Natural gas

      7         -         136         143    
    

Power

      -         -         360         360    

Genco

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         4         4    
  

Natural gas

      2         -         -         2    
    

Power

      -         -         8         8    

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 million of receivables, payables, and accrued income, net.

 

In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance required disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also required information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. This guidance was effective for us as of January 1, 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which became effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2011:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2011

      $ 96         $ 57         $         (a )       $ 29         $ 10   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (5 )         -           (a )         (3 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (14 )         (9 )         (a )         (3 )         (2 ) 

Purchases

        1           1           (a )         -           -   

Settlements

        (15 )         (8 )         (a )         (5 )         (2 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (14 )       $ (8 )       $ (a )       $ (4 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2011

      $ (120 )       $ (12 )       $ (108 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (20 )         (1 )         (19 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (20 )         (1 )         (19 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        22           2           20           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (18 )       $ (1 )       $ (17 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2011

      $ 31         $ 2         $ (325 )       $ 3         $ 351   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (15 )         -           -           (1 )         (14 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        66           (1 )         77           (a )         (10 ) 

Total realized and unrealized gains (losses)

        56           (1 )         77           (1 )         (19 ) 

Purchases

        50           29           -           -           21   

Sales

        (7 )         -           -           -           (7 ) 

Settlements

        (16 )         (6 )         44           (1 )         (53 ) 

Transfers into Level 3

        1           -           -           -           1   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ (1 )       $ 68         $ (1 )       $ (7 ) 

Uranium:

                         

Beginning balance at April 1, 2011

      $ 1         $ 1         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (3 )         (3 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (3 )         (3 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2010:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2010

      $ 54         $ 31         $         (a )       $ 18         $ 5   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (8 )         -           (a )         (6 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (17 )         (9 )         (a )         (6 )         (2 ) 

Purchases

        33           17           (a )         11           5   

Settlements

        (41 )         (23 )         (a )         (13 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (16 )       $ (9 )       $ (a )       $ (5 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2010

      $ (162 )       $ (18 )       $ (144 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (6 )         (1 )         (5 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (6 )         (1 )         (5 )         -           -   

Purchases

        -           -           -           -           -   

Settlements

        30           4           26           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (6 )       $ (1 )       $ (5 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2010

      $ 37         $ 5         $ (554 )       $ 3         $ 583   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       6           -           -           -           6   

Included in OCI

        (18 )         -           -           -           (18 ) 

Included in regulatory assets/liabilities

        29           1           98           (a )         (70 ) 

Total realized and unrealized gains (losses)

        17           1           98           -           (82 ) 

Purchases

        25           5           17           (2 )         5   

Sales

        2           -           -           3           (1 ) 

Settlements

        (19 )         (6 )         33           (1 )         (45 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (7 )         -           -           -           (7 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (5 )       $ (3 )       $ 67         $ -         $ (69 ) 

Uranium:

                         

Beginning balance at April 1, 2010

      $ (3 )       $ (3 )       $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (1 )         (1 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (1 )         (1 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ -         $ -         $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2011:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2011

      $ 51         $ 30         $         (a )       $ 17         $ 4   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        17           -           (a )         12           5   

Included in regulatory assets/liabilities

        22           22           (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        39           22           (a )         12           5   

Purchases

        2           2           (a )         -           -   

Settlements

        (24 )         (13 )         (a )         (8 )         (3 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 30         $ 18         $ (a )       $ 9         $ 3   

Natural gas:

                         

Beginning balance at January 1, 2011

      $ (148 )       $ (14 )       $ (134 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (13 )         (1 )         (12 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (13 )         (1 )         (12 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        43           4           39           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 9         $ 1         $ 8         $ -         $ -   

Power:

                         

Beginning balance at January 1, 2011

      $ 36         $ 2         $ (352 )       $ 3         $ 383   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (18 )         -           -           (1 )         (17 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        64           6           47           (a )         11   

Total realized and unrealized gains (losses)

        51           6           47           (1 )         (1 ) 

Purchases

        59           29           -           -           30   

Sales

        (16 )         -           -           -           (16 ) 

Settlements

        (16 )         (12 )         101           (1 )         (104 ) 

Transfers into Level 3

        1           (1 )         -           -           2   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ -         $ 64         $ (1 )       $ (4 ) 

Uranium:

                         

Beginning balance at January 1, 2011

      $ 2         $ 2         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (4 )         (4 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (4 )         (4 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2010:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2010

      $ 60         $ 32         $         (a )       $ 21         $ 7   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (10 )         -           (a )         (8 )         (2 ) 

Included in regulatory assets/liabilities

        (11 )         (11 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (21 )         (11 )         (a )         (8 )         (2 ) 

Purchases

        32           18           (a )         11           3   

Settlements

        (42 )         (23 )         (a )         (14 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (18 )       $ (10 )       $ (a )       $ (6 )       $ (2 ) 

Natural gas:

                         

Beginning balance at January 1, 2010

      $ (67 )       $ (6 )       $ (61 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (109 )         (14 )         (95 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (109 )         (14 )         (95 )         -           -   

Purchases

        (4 )         -           (4 )         -           -   

Settlements

        42           5           37           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (81 )       $ (10 )       $ (71 )       $ -         $ -   

Power:

                         

Beginning balance at January 1, 2010

      $ 38         $ (1 )       $ (422 )       $ 1         $ 460   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       24           -           -           2           22   

Included in OCI

        6           -           -           -           6   

Included in regulatory assets/liabilities

        7           13           (69 )         (a )         63   

Total realized and unrealized gains (losses)

        37           13           (69 )         2           91   

Purchases

        38           4           17           (4 )         21   

Sales

        (5 )         1           -           5           (11 ) 

Settlements

        (29 )         (9 )         68           (1 )         (87 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (24 )         (3 )         -           -           (21 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (7 )       $ 1         $ (79 )       $ 1         $ 70   

Uranium:

                         

Beginning balance at January 1, 2010

      $ (2 )       $ (2 )       $ (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (2 )         (2 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (2 )         (2 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (1 )       $ (1 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

Transfers out of Level 3 represent 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 into Level 3 represent existing assets and liabilities that were previously classified as a higher level but were recategorized to Level 3 because the lowest significant input became unobservable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable in active markets compared with previous periods for the quarters ended June 30, 2011, and 2010. Any reclassifications are reported at the fair value measurement reported at the beginning of the period in which the changes occur. For the three and six months ended June 30, 2011, and 2010, there were no transfers into or out of Level 1.

The Ameren Companies' carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. 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.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at June 30, 2011, and December 31, 2010:

 

      June 30, 2011      December 31, 2010  
     

Carrying

Amount

     

Fair

Value

     

Carrying

Amount

     

Fair

Value

  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,859       $    7,666       $ 7,008       $    7,661   

Preferred stock

      142         102         142         102   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,954       $ 4,378       $ 3,954       $ 4,281   

Preferred stock

      80         61         80         62   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,956       $ 1,807       $ 2,067   

Preferred stock

      62         41         62         40   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 843       $ 824       $ 826   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Preferred stock not subject to mandatory redemption of the Ameren subsidiaries along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.
Fair Value Measurements 

NOTE 7 - FAIR VALUE MEASUREMENTS

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.

See Note 8 - Fair Value Measurements under Part II, Item 8, of the Form 10-K for additional information of the definition of fair value and the fair value hierarchy.

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded losses totaling less than $1 million in the first six months of 2011 and gains totaling less than $1 million in the first six months of 2010 related to valuation adjustments for counterparty default risk. At June 30, 2011, the counterparty default risk valuation adjustment related to net derivative assets totaled $1 million and less than $1 million for Ameren and Genco, respectively. The counterparty default risk valuation adjustment related to net derivative liabilities totaled less than $1 million and $11 million for Ameren Missouri and Ameren Illinois, respectively. At December 31, 2010, the counterparty default risk valuation adjustment related to derivative contracts totaled $2 million, less than $1 million, $21 million, and less than $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of June 30, 2011:

 

          

Quoted Prices in

Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

          Total      

Assets:

              

Ameren(a)             

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 72       $ 72   
 

Natural gas

      3         -         3         6   
 

Power

      -         18         174         192   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AMO

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         43         43   
 

Power

      -         2         28         30   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AIC

  

Derivative assets - commodity contracts(b):

            
 

Natural gas

      -         -         2         2   
   

Power

      -         -         69         69   

Genco

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         22         22   
 

Natural gas

      1         -         -         1   
   

Power

      -         -         4         4   

Liabilities:

              

Ameren(a)

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 4       $ 4   
 

Natural gas

      18         -         120         138   
 

Power

      -         16         57         73   
   

Uranium

      -         -         2         2   

AMO

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         2         2   
 

Natural gas

      9         -         11         20   
 

Power

      -         1         3         4   
   

Uranium

      -         -         2         2   

AIC

  

Derivative liabilities - commodity contracts(b):

            
 

Natural gas

      5         -         108         113   
   

Power

      -         -         273         273   

Genco

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         1         1   
 

Natural gas

      2         -         -         2   
   

Power

      -         -         3         3   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 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, 2010:

 

           

Quoted Prices in
Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

              Total           

Assets:

               

Ameren(a)

    Derivative assets - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 64       $ 64    
  

Natural gas

      3         -         2         5    
  

Power

      -         17         86         103    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AMO

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         37         37    
  

Natural gas

      -         -         1         1    
  

Power

      -         3         5         8    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AIC

    Derivative assets - commodity contracts(b):            
  

Natural gas

      -         -         2         2    
    

Power

      -         -         8         8    

Genco

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         21         21    
  

Natural gas

      1         -         -         1    
    

Power

      -         -         11         11    

Liabilities:

               

Ameren(a)

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 13       $ 13    
  

Natural gas

      21         -         150         171    
    

Power

      -         19         50         69    

AMO

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         7         7    
  

Natural gas

      9         -         15         24    
    

Power

      -         3         3         6    

AIC

    Derivative liabilities - commodity contracts(b):            
  

Natural gas

      7         -         136         143    
    

Power

      -         -         360         360    

Genco

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         4         4    
  

Natural gas

      2         -         -         2    
    

Power

      -         -         8         8    

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 million of receivables, payables, and accrued income, net.

 

In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance required disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also required information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. This guidance was effective for us as of January 1, 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which became effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2011:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2011

      $ 96         $ 57         $         (a )       $ 29         $ 10   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (5 )         -           (a )         (3 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (14 )         (9 )         (a )         (3 )         (2 ) 

Purchases

        1           1           (a )         -           -   

Settlements

        (15 )         (8 )         (a )         (5 )         (2 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (14 )       $ (8 )       $ (a )       $ (4 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2011

      $ (120 )       $ (12 )       $ (108 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (20 )         (1 )         (19 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (20 )         (1 )         (19 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        22           2           20           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (18 )       $ (1 )       $ (17 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2011

      $ 31         $ 2         $ (325 )       $ 3         $ 351   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (15 )         -           -           (1 )         (14 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        66           (1 )         77           (a )         (10 ) 

Total realized and unrealized gains (losses)

        56           (1 )         77           (1 )         (19 ) 

Purchases

        50           29           -           -           21   

Sales

        (7 )         -           -           -           (7 ) 

Settlements

        (16 )         (6 )         44           (1 )         (53 ) 

Transfers into Level 3

        1           -           -           -           1   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ (1 )       $ 68         $ (1 )       $ (7 ) 

Uranium:

                         

Beginning balance at April 1, 2011

      $ 1         $ 1         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (3 )         (3 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (3 )         (3 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2010:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2010

      $ 54         $ 31         $         (a )       $ 18         $ 5   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (8 )         -           (a )         (6 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (17 )         (9 )         (a )         (6 )         (2 ) 

Purchases

        33           17           (a )         11           5   

Settlements

        (41 )         (23 )         (a )         (13 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (16 )       $ (9 )       $ (a )       $ (5 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2010

      $ (162 )       $ (18 )       $ (144 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (6 )         (1 )         (5 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (6 )         (1 )         (5 )         -           -   

Purchases

        -           -           -           -           -   

Settlements

        30           4           26           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (6 )       $ (1 )       $ (5 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2010

      $ 37         $ 5         $ (554 )       $ 3         $ 583   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       6           -           -           -           6   

Included in OCI

        (18 )         -           -           -           (18 ) 

Included in regulatory assets/liabilities

        29           1           98           (a )         (70 ) 

Total realized and unrealized gains (losses)

        17           1           98           -           (82 ) 

Purchases

        25           5           17           (2 )         5   

Sales

        2           -           -           3           (1 ) 

Settlements

        (19 )         (6 )         33           (1 )         (45 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (7 )         -           -           -           (7 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (5 )       $ (3 )       $ 67         $ -         $ (69 ) 

Uranium:

                         

Beginning balance at April 1, 2010

      $ (3 )       $ (3 )       $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (1 )         (1 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (1 )         (1 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ -         $ -         $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2011:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2011

      $ 51         $ 30         $         (a )       $ 17         $ 4   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        17           -           (a )         12           5   

Included in regulatory assets/liabilities

        22           22           (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        39           22           (a )         12           5   

Purchases

        2           2           (a )         -           -   

Settlements

        (24 )         (13 )         (a )         (8 )         (3 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 30         $ 18         $ (a )       $ 9         $ 3   

Natural gas:

                         

Beginning balance at January 1, 2011

      $ (148 )       $ (14 )       $ (134 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (13 )         (1 )         (12 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (13 )         (1 )         (12 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        43           4           39           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 9         $ 1         $ 8         $ -         $ -   

Power:

                         

Beginning balance at January 1, 2011

      $ 36         $ 2         $ (352 )       $ 3         $ 383   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (18 )         -           -           (1 )         (17 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        64           6           47           (a )         11   

Total realized and unrealized gains (losses)

        51           6           47           (1 )         (1 ) 

Purchases

        59           29           -           -           30   

Sales

        (16 )         -           -           -           (16 ) 

Settlements

        (16 )         (12 )         101           (1 )         (104 ) 

Transfers into Level 3

        1           (1 )         -           -           2   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ -         $ 64         $ (1 )       $ (4 ) 

Uranium:

                         

Beginning balance at January 1, 2011

      $ 2         $ 2         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (4 )         (4 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (4 )         (4 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2010:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2010

      $ 60         $ 32         $         (a )       $ 21         $ 7   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (10 )         -           (a )         (8 )         (2 ) 

Included in regulatory assets/liabilities

        (11 )         (11 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (21 )         (11 )         (a )         (8 )         (2 ) 

Purchases

        32           18           (a )         11           3   

Settlements

        (42 )         (23 )         (a )         (14 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (18 )       $ (10 )       $ (a )       $ (6 )       $ (2 ) 

Natural gas:

                         

Beginning balance at January 1, 2010

      $ (67 )       $ (6 )       $ (61 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (109 )         (14 )         (95 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (109 )         (14 )         (95 )         -           -   

Purchases

        (4 )         -           (4 )         -           -   

Settlements

        42           5           37           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (81 )       $ (10 )       $ (71 )       $ -         $ -   

Power:

                         

Beginning balance at January 1, 2010

      $ 38         $ (1 )       $ (422 )       $ 1         $ 460   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       24           -           -           2           22   

Included in OCI

        6           -           -           -           6   

Included in regulatory assets/liabilities

        7           13           (69 )         (a )         63   

Total realized and unrealized gains (losses)

        37           13           (69 )         2           91   

Purchases

        38           4           17           (4 )         21   

Sales

        (5 )         1           -           5           (11 ) 

Settlements

        (29 )         (9 )         68           (1 )         (87 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (24 )         (3 )         -           -           (21 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (7 )       $ 1         $ (79 )       $ 1         $ 70   

Uranium:

                         

Beginning balance at January 1, 2010

      $ (2 )       $ (2 )       $ (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (2 )         (2 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (2 )         (2 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (1 )       $ (1 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

Transfers out of Level 3 represent 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 into Level 3 represent existing assets and liabilities that were previously classified as a higher level but were recategorized to Level 3 because the lowest significant input became unobservable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable in active markets compared with previous periods for the quarters ended June 30, 2011, and 2010. Any reclassifications are reported at the fair value measurement reported at the beginning of the period in which the changes occur. For the three and six months ended June 30, 2011, and 2010, there were no transfers into or out of Level 1.

The Ameren Companies' carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. 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.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at June 30, 2011, and December 31, 2010:

 

      June 30, 2011      December 31, 2010  
     

Carrying

Amount

     

Fair

Value

     

Carrying

Amount

     

Fair

Value

  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,859       $    7,666       $ 7,008       $    7,661   

Preferred stock

      142         102         142         102   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,954       $ 4,378       $ 3,954       $ 4,281   

Preferred stock

      80         61         80         62   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,956       $ 1,807       $ 2,067   

Preferred stock

      62         41         62         40   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 843       $ 824       $ 826   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Preferred stock not subject to mandatory redemption of the Ameren subsidiaries along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.
Fair Value Measurements 

NOTE 7 - FAIR VALUE MEASUREMENTS

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.

See Note 8 - Fair Value Measurements under Part II, Item 8, of the Form 10-K for additional information of the definition of fair value and the fair value hierarchy.

In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded losses totaling less than $1 million in the first six months of 2011 and gains totaling less than $1 million in the first six months of 2010 related to valuation adjustments for counterparty default risk. At June 30, 2011, the counterparty default risk valuation adjustment related to net derivative assets totaled $1 million and less than $1 million for Ameren and Genco, respectively. The counterparty default risk valuation adjustment related to net derivative liabilities totaled less than $1 million and $11 million for Ameren Missouri and Ameren Illinois, respectively. At December 31, 2010, the counterparty default risk valuation adjustment related to derivative contracts totaled $2 million, less than $1 million, $21 million, and less than $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of June 30, 2011:

 

          

Quoted Prices in

Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

          Total      

Assets:

              

Ameren(a)             

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 72       $ 72   
 

Natural gas

      3         -         3         6   
 

Power

      -         18         174         192   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AMO

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         43         43   
 

Power

      -         2         28         30   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AIC

  

Derivative assets - commodity contracts(b):

            
 

Natural gas

      -         -         2         2   
   

Power

      -         -         69         69   

Genco

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         22         22   
 

Natural gas

      1         -         -         1   
   

Power

      -         -         4         4   

Liabilities:

              

Ameren(a)

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 4       $ 4   
 

Natural gas

      18         -         120         138   
 

Power

      -         16         57         73   
   

Uranium

      -         -         2         2   

AMO

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         2         2   
 

Natural gas

      9         -         11         20   
 

Power

      -         1         3         4   
   

Uranium

      -         -         2         2   

AIC

  

Derivative liabilities - commodity contracts(b):

            
 

Natural gas

      5         -         108         113   
   

Power

      -         -         273         273   

Genco

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         1         1   
 

Natural gas

      2         -         -         2   
   

Power

      -         -         3         3   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 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, 2010:

 

           

Quoted Prices in
Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

              Total           

Assets:

               

Ameren(a)

    Derivative assets - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 64       $ 64    
  

Natural gas

      3         -         2         5    
  

Power

      -         17         86         103    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AMO

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         37         37    
  

Natural gas

      -         -         1         1    
  

Power

      -         3         5         8    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AIC

    Derivative assets - commodity contracts(b):            
  

Natural gas

      -         -         2         2    
    

Power

      -         -         8         8    

Genco

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         21         21    
  

Natural gas

      1         -         -         1    
    

Power

      -         -         11         11    

Liabilities:

               

Ameren(a)

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 13       $ 13    
  

Natural gas

      21         -         150         171    
    

Power

      -         19         50         69    

AMO

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         7         7    
  

Natural gas

      9         -         15         24    
    

Power

      -         3         3         6    

AIC

    Derivative liabilities - commodity contracts(b):            
  

Natural gas

      7         -         136         143    
    

Power

      -         -         360         360    

Genco

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         4         4    
  

Natural gas

      2         -         -         2    
    

Power

      -         -         8         8    

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 million of receivables, payables, and accrued income, net.

 

In January 2010, the FASB issued amended authoritative guidance regarding fair value measurements. This guidance required disclosures regarding significant transfers into and out of Level 1 and Level 2 fair value measurements. It also required information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. This guidance was effective for us as of January 1, 2010, with the exception of guidance applicable to detailed Level 3 reconciliation disclosures, which became effective for us as of January 1, 2011. The adoption of this guidance did not have a material impact on our results of operations, financial position, or liquidity because it provides enhanced disclosure requirements only.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2011:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2011

      $ 96         $ 57         $         (a )       $ 29         $ 10   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (5 )         -           (a )         (3 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (14 )         (9 )         (a )         (3 )         (2 ) 

Purchases

        1           1           (a )         -           -   

Settlements

        (15 )         (8 )         (a )         (5 )         (2 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (14 )       $ (8 )       $ (a )       $ (4 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2011

      $ (120 )       $ (12 )       $ (108 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (20 )         (1 )         (19 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (20 )         (1 )         (19 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        22           2           20           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (18 )       $ (1 )       $ (17 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2011

      $ 31         $ 2         $ (325 )       $ 3         $ 351   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (15 )         -           -           (1 )         (14 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        66           (1 )         77           (a )         (10 ) 

Total realized and unrealized gains (losses)

        56           (1 )         77           (1 )         (19 ) 

Purchases

        50           29           -           -           21   

Sales

        (7 )         -           -           -           (7 ) 

Settlements

        (16 )         (6 )         44           (1 )         (53 ) 

Transfers into Level 3

        1           -           -           -           1   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ (1 )       $ 68         $ (1 )       $ (7 ) 

Uranium:

                         

Beginning balance at April 1, 2011

      $ 1         $ 1         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (3 )         (3 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (3 )         (3 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2010:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2010

      $ 54         $ 31         $         (a )       $ 18         $ 5   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (8 )         -           (a )         (6 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (17 )         (9 )         (a )         (6 )         (2 ) 

Purchases

        33           17           (a )         11           5   

Settlements

        (41 )         (23 )         (a )         (13 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (16 )       $ (9 )       $ (a )       $ (5 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2010

      $ (162 )       $ (18 )       $ (144 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (6 )         (1 )         (5 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (6 )         (1 )         (5 )         -           -   

Purchases

        -           -           -           -           -   

Settlements

        30           4           26           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (6 )       $ (1 )       $ (5 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2010

      $ 37         $ 5         $ (554 )       $ 3         $ 583   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       6           -           -           -           6   

Included in OCI

        (18 )         -           -           -           (18 ) 

Included in regulatory assets/liabilities

        29           1           98           (a )         (70 ) 

Total realized and unrealized gains (losses)

        17           1           98           -           (82 ) 

Purchases

        25           5           17           (2 )         5   

Sales

        2           -           -           3           (1 ) 

Settlements

        (19 )         (6 )         33           (1 )         (45 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (7 )         -           -           -           (7 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (5 )       $ (3 )       $ 67         $ -         $ (69 ) 

Uranium:

                         

Beginning balance at April 1, 2010

      $ (3 )       $ (3 )       $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (1 )         (1 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (1 )         (1 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ -         $ -         $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2011:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2011

      $ 51         $ 30         $         (a )       $ 17         $ 4   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        17           -           (a )         12           5   

Included in regulatory assets/liabilities

        22           22           (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        39           22           (a )         12           5   

Purchases

        2           2           (a )         -           -   

Settlements

        (24 )         (13 )         (a )         (8 )         (3 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 30         $ 18         $ (a )       $ 9         $ 3   

Natural gas:

                         

Beginning balance at January 1, 2011

      $ (148 )       $ (14 )       $ (134 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (13 )         (1 )         (12 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (13 )         (1 )         (12 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        43           4           39           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 9         $ 1         $ 8         $ -         $ -   

Power:

                         

Beginning balance at January 1, 2011

      $ 36         $ 2         $ (352 )       $ 3         $ 383   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (18 )         -           -           (1 )         (17 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        64           6           47           (a )         11   

Total realized and unrealized gains (losses)

        51           6           47           (1 )         (1 ) 

Purchases

        59           29           -           -           30   

Sales

        (16 )         -           -           -           (16 ) 

Settlements

        (16 )         (12 )         101           (1 )         (104 ) 

Transfers into Level 3

        1           (1 )         -           -           2   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ -         $ 64         $ (1 )       $ (4 ) 

Uranium:

                         

Beginning balance at January 1, 2011

      $ 2         $ 2         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (4 )         (4 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (4 )         (4 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2010:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2010

      $ 60         $ 32         $         (a )       $ 21         $ 7   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (10 )         -           (a )         (8 )         (2 ) 

Included in regulatory assets/liabilities

        (11 )         (11 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (21 )         (11 )         (a )         (8 )         (2 ) 

Purchases

        32           18           (a )         11           3   

Settlements

        (42 )         (23 )         (a )         (14 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (18 )       $ (10 )       $ (a )       $ (6 )       $ (2 ) 

Natural gas:

                         

Beginning balance at January 1, 2010

      $ (67 )       $ (6 )       $ (61 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (109 )         (14 )         (95 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (109 )         (14 )         (95 )         -           -   

Purchases

        (4 )         -           (4 )         -           -   

Settlements

        42           5           37           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (81 )       $ (10 )       $ (71 )       $ -         $ -   

Power:

                         

Beginning balance at January 1, 2010

      $ 38         $ (1 )       $ (422 )       $ 1         $ 460   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       24           -           -           2           22   

Included in OCI

        6           -           -           -           6   

Included in regulatory assets/liabilities

        7           13           (69 )         (a )         63   

Total realized and unrealized gains (losses)

        37           13           (69 )         2           91   

Purchases

        38           4           17           (4 )         21   

Sales

        (5 )         1           -           5           (11 ) 

Settlements

        (29 )         (9 )         68           (1 )         (87 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (24 )         (3 )         -           -           (21 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (7 )       $ 1         $ (79 )       $ 1         $ 70   

Uranium:

                         

Beginning balance at January 1, 2010

      $ (2 )       $ (2 )       $ (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (2 )         (2 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (2 )         (2 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (1 )       $ (1 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

Transfers out of Level 3 represent 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 into Level 3 represent existing assets and liabilities that were previously classified as a higher level but were recategorized to Level 3 because the lowest significant input became unobservable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable in active markets compared with previous periods for the quarters ended June 30, 2011, and 2010. Any reclassifications are reported at the fair value measurement reported at the beginning of the period in which the changes occur. For the three and six months ended June 30, 2011, and 2010, there were no transfers into or out of Level 1.

The Ameren Companies' carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. 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.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at June 30, 2011, and December 31, 2010:

 

      June 30, 2011      December 31, 2010  
     

Carrying

Amount

     

Fair

Value

     

Carrying

Amount

     

Fair

Value

  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,859       $    7,666       $ 7,008       $    7,661   

Preferred stock

      142         102         142         102   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,954       $ 4,378       $ 3,954       $ 4,281   

Preferred stock

      80         61         80         62   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,956       $ 1,807       $ 2,067   

Preferred stock

      62         41         62         40   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 843       $ 824       $ 826   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Preferred stock not subject to mandatory redemption of the Ameren subsidiaries along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.
Related Party Transactions
6 Months Ended
Jun. 30, 2011
Related Party Transactions
Text Block 
Ameren Illinois [Member]
 
Related Party Transactions
Text Block 
Ameren Energy Generating Company [Member]
 
Related Party Transactions
Text Block 
Union Electric Company [Member]
 
Related Party Transactions
Text Block 
Related Party Transactions 

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren's financial statements. 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.

Electric Power Supply Agreements

Ameren Illinois, as an electric load serving entity, must acquire energy sufficient to meet its obligations to customers. In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products from June 1, 2011, through May 31, 2014. Marketing Company and Ameren Missouri were winning suppliers in Ameren Illinois' energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements where Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2013, and approximately 650,000 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2014. In May 2011, Ameren Missouri and Ameren Illinois entered into energy product agreements where Ameren Missouri will sell and Ameren Illinois will purchase approximately 16,800 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 40,800 megawatthours at approximately $29 per megawatthour during the twelve months ending May 31, 2013, and approximately 40,800 megawatthours at approximately $28 per megawatthour during the twelve months ending May 31, 2014. The 2012 and 2013 energy product agreements between Ameren Missouri and Ameren Illinois are for off-peak hours only.

Joint Ownership Agreement and Asset Transfer

ATXI and Ameren Illinois have a joint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this

agreement, Ameren Illinois and ATXI are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. Through this joint ownership agreement, Ameren Illinois has a variable interest in ATXI, but Ameren Illinois is not the primary beneficiary. Ameren is the primary beneficiary of ATXI, and therefore consolidates ATXI. Currently, there are no construction projects or joint ownership of existing assets under this agreement.

In January 2011, ATXI repaid advances for the construction of transmission assets to Ameren Illinois in the amount of $52 million, including $3 million of accrued interest.

In March 2011, Ameren Illinois and ATXI signed an agreement to transfer, at cost, all of ATXI's construction work in progress assets related to the construction of a transmission line to Ameren Illinois for $20 million. In April 2011, Ameren Illinois paid ATXI for these assets.

Collateral Postings

Under the terms of the 2011, 2010 and 2009 Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity and energy products, and Marketing Company, as a winning supplier of capacity, financial energy swaps and energy products, may be required to post collateral. As of December 31, 2010, and June 30, 2011, there were no collateral postings required of Ameren Missouri or Marketing Company related to the 2011, 2010 and 2009 Illinois power procurement agreements.

Money Pools

See Note 3 - Credit Facility Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

The following table presents the impact on Ameren Missouri, Ameren Illinois and Genco of related party transactions for the three and six months ended June 30, 2011, and 2010. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Credit Facility Borrowings and Liquidity of this report.

 

      Income Statement Line Item            Three Months     Six Months  
Agreement               AMO     AIC     Genco     AMO     AIC     Genco  

Genco and EEI power supply agreements with Marketing Company

   

Operating Revenues

      2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 485   
            2010         (a )      (a )      254        (a )      (a )      518   

Genco gas sales to Medina Valley

   

Operating Revenues

      2011         (a )      (a )      (b )      (a )      (a )      2   
            2010         (a )      (a )      -        (a )      (a )      1   

Total Operating Revenues

         2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 487   
            2010         (a )      (a )      254        (a )      (a )      519   

AIC power supply agreements with Marketing Company

   

Purchased Power

      2011       $ (a )    $ 48      $ (a )    $ (a )    $ 94      $ (a ) 
            2010         (a )      59        (a )      (a )      132        (a ) 

EEI power supply agreement with Marketing Company

   

Purchased Power

      2011         (a )      (a )      12        (a )      (a )      12   
            2010         (a )      (a )      4        (a )      (a )      4   

Total Purchased Power

         2011       $ (a )    $ 48      $ 12      $ (a )    $ 94      $ 12   
            2010         (a )      59        4        (a )      132        4   

Ameren Services support services agreement

   

Other Operations and Maintenance

      2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         32        25        6        68        53        13   

AFS support services agreement

   

Other Operations and Maintenance

      2011         (a )      (a )      (a )      (a )      (a )      (a ) 
            2010         2        (b )      (b )      3        (b )      1   

Insurance premiums(c)

   

Other Operations and Maintenance

      2011         (b )      (a )      -        (b )      (a )      -   
            2010         (b )      (a )      -        1        (a )      -   

Total Other Operations and Maintenance Expenses

         2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         34        25        6        72        53        13   

Money pool borrowings (advances)

   

Interest Charges

      2011       $ -      $ -      $ (b )    $ -      $ -      $ (b ) 
            2010         -        -        (b )      -        -        (b ) 

 

(a) Not applicable.
(b) Amount less than $1 million.
(c) Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
Related Party Transactions 

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren's financial statements. 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.

Electric Power Supply Agreements

Ameren Illinois, as an electric load serving entity, must acquire energy sufficient to meet its obligations to customers. In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products from June 1, 2011, through May 31, 2014. Marketing Company and Ameren Missouri were winning suppliers in Ameren Illinois' energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements where Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2013, and approximately 650,000 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2014. In May 2011, Ameren Missouri and Ameren Illinois entered into energy product agreements where Ameren Missouri will sell and Ameren Illinois will purchase approximately 16,800 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 40,800 megawatthours at approximately $29 per megawatthour during the twelve months ending May 31, 2013, and approximately 40,800 megawatthours at approximately $28 per megawatthour during the twelve months ending May 31, 2014. The 2012 and 2013 energy product agreements between Ameren Missouri and Ameren Illinois are for off-peak hours only.

Joint Ownership Agreement and Asset Transfer

ATXI and Ameren Illinois have a joint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this

agreement, Ameren Illinois and ATXI are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. Through this joint ownership agreement, Ameren Illinois has a variable interest in ATXI, but Ameren Illinois is not the primary beneficiary. Ameren is the primary beneficiary of ATXI, and therefore consolidates ATXI. Currently, there are no construction projects or joint ownership of existing assets under this agreement.

In January 2011, ATXI repaid advances for the construction of transmission assets to Ameren Illinois in the amount of $52 million, including $3 million of accrued interest.

In March 2011, Ameren Illinois and ATXI signed an agreement to transfer, at cost, all of ATXI's construction work in progress assets related to the construction of a transmission line to Ameren Illinois for $20 million. In April 2011, Ameren Illinois paid ATXI for these assets.

Collateral Postings

Under the terms of the 2011, 2010 and 2009 Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity and energy products, and Marketing Company, as a winning supplier of capacity, financial energy swaps and energy products, may be required to post collateral. As of December 31, 2010, and June 30, 2011, there were no collateral postings required of Ameren Missouri or Marketing Company related to the 2011, 2010 and 2009 Illinois power procurement agreements.

Money Pools

See Note 3 - Credit Facility Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

The following table presents the impact on Ameren Missouri, Ameren Illinois and Genco of related party transactions for the three and six months ended June 30, 2011, and 2010. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Credit Facility Borrowings and Liquidity of this report.

 

      Income Statement Line Item            Three Months     Six Months  
Agreement               AMO     AIC     Genco     AMO     AIC     Genco  

Genco and EEI power supply agreements with Marketing Company

   

Operating Revenues

      2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 485   
            2010         (a )      (a )      254        (a )      (a )      518   

Genco gas sales to Medina Valley

   

Operating Revenues

      2011         (a )      (a )      (b )      (a )      (a )      2   
            2010         (a )      (a )      -        (a )      (a )      1   

Total Operating Revenues

         2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 487   
            2010         (a )      (a )      254        (a )      (a )      519   

AIC power supply agreements with Marketing Company

   

Purchased Power

      2011       $ (a )    $ 48      $ (a )    $ (a )    $ 94      $ (a ) 
            2010         (a )      59        (a )      (a )      132        (a ) 

EEI power supply agreement with Marketing Company

   

Purchased Power

      2011         (a )      (a )      12        (a )      (a )      12   
            2010         (a )      (a )      4        (a )      (a )      4   

Total Purchased Power

         2011       $ (a )    $ 48      $ 12      $ (a )    $ 94      $ 12   
            2010         (a )      59        4        (a )      132        4   

Ameren Services support services agreement

   

Other Operations and Maintenance

      2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         32        25        6        68        53        13   

AFS support services agreement

   

Other Operations and Maintenance

      2011         (a )      (a )      (a )      (a )      (a )      (a ) 
            2010         2        (b )      (b )      3        (b )      1   

Insurance premiums(c)

   

Other Operations and Maintenance

      2011         (b )      (a )      -        (b )      (a )      -   
            2010         (b )      (a )      -        1        (a )      -   

Total Other Operations and Maintenance Expenses

         2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         34        25        6        72        53        13   

Money pool borrowings (advances)

   

Interest Charges

      2011       $ -      $ -      $ (b )    $ -      $ -      $ (b ) 
            2010         -        -        (b )      -        -        (b ) 

 

(a) Not applicable.
(b) Amount less than $1 million.
(c) Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
Related Party Transactions 

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren's financial statements. 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.

Electric Power Supply Agreements

Ameren Illinois, as an electric load serving entity, must acquire energy sufficient to meet its obligations to customers. In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products from June 1, 2011, through May 31, 2014. Marketing Company and Ameren Missouri were winning suppliers in Ameren Illinois' energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements where Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2013, and approximately 650,000 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2014. In May 2011, Ameren Missouri and Ameren Illinois entered into energy product agreements where Ameren Missouri will sell and Ameren Illinois will purchase approximately 16,800 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 40,800 megawatthours at approximately $29 per megawatthour during the twelve months ending May 31, 2013, and approximately 40,800 megawatthours at approximately $28 per megawatthour during the twelve months ending May 31, 2014. The 2012 and 2013 energy product agreements between Ameren Missouri and Ameren Illinois are for off-peak hours only.

Joint Ownership Agreement and Asset Transfer

ATXI and Ameren Illinois have a joint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this

agreement, Ameren Illinois and ATXI are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. Through this joint ownership agreement, Ameren Illinois has a variable interest in ATXI, but Ameren Illinois is not the primary beneficiary. Ameren is the primary beneficiary of ATXI, and therefore consolidates ATXI. Currently, there are no construction projects or joint ownership of existing assets under this agreement.

In January 2011, ATXI repaid advances for the construction of transmission assets to Ameren Illinois in the amount of $52 million, including $3 million of accrued interest.

In March 2011, Ameren Illinois and ATXI signed an agreement to transfer, at cost, all of ATXI's construction work in progress assets related to the construction of a transmission line to Ameren Illinois for $20 million. In April 2011, Ameren Illinois paid ATXI for these assets.

Collateral Postings

Under the terms of the 2011, 2010 and 2009 Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity and energy products, and Marketing Company, as a winning supplier of capacity, financial energy swaps and energy products, may be required to post collateral. As of December 31, 2010, and June 30, 2011, there were no collateral postings required of Ameren Missouri or Marketing Company related to the 2011, 2010 and 2009 Illinois power procurement agreements.

Money Pools

See Note 3 - Credit Facility Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

The following table presents the impact on Ameren Missouri, Ameren Illinois and Genco of related party transactions for the three and six months ended June 30, 2011, and 2010. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Credit Facility Borrowings and Liquidity of this report.

 

      Income Statement Line Item            Three Months     Six Months  
Agreement               AMO     AIC     Genco     AMO     AIC     Genco  

Genco and EEI power supply agreements with Marketing Company

   

Operating Revenues

      2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 485   
            2010         (a )      (a )      254        (a )      (a )      518   

Genco gas sales to Medina Valley

   

Operating Revenues

      2011         (a )      (a )      (b )      (a )      (a )      2   
            2010         (a )      (a )      -        (a )      (a )      1   

Total Operating Revenues

         2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 487   
            2010         (a )      (a )      254        (a )      (a )      519   

AIC power supply agreements with Marketing Company

   

Purchased Power

      2011       $ (a )    $ 48      $ (a )    $ (a )    $ 94      $ (a ) 
            2010         (a )      59        (a )      (a )      132        (a ) 

EEI power supply agreement with Marketing Company

   

Purchased Power

      2011         (a )      (a )      12        (a )      (a )      12   
            2010         (a )      (a )      4        (a )      (a )      4   

Total Purchased Power

         2011       $ (a )    $ 48      $ 12      $ (a )    $ 94      $ 12   
            2010         (a )      59        4        (a )      132        4   

Ameren Services support services agreement

   

Other Operations and Maintenance

      2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         32        25        6        68        53        13   

AFS support services agreement

   

Other Operations and Maintenance

      2011         (a )      (a )      (a )      (a )      (a )      (a ) 
            2010         2        (b )      (b )      3        (b )      1   

Insurance premiums(c)

   

Other Operations and Maintenance

      2011         (b )      (a )      -        (b )      (a )      -   
            2010         (b )      (a )      -        1        (a )      -   

Total Other Operations and Maintenance Expenses

         2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         34        25        6        72        53        13   

Money pool borrowings (advances)

   

Interest Charges

      2011       $ -      $ -      $ (b )    $ -      $ -      $ (b ) 
            2010         -        -        (b )      -        -        (b ) 

 

(a) Not applicable.
(b) Amount less than $1 million.
(c) Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
Related Party Transactions 

NOTE 8 - RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of natural gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren's financial statements. 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.

Electric Power Supply Agreements

Ameren Illinois, as an electric load serving entity, must acquire energy sufficient to meet its obligations to customers. In 2011, Ameren Illinois used a RFP process administered by the IPA to procure energy products from June 1, 2011, through May 31, 2014. Marketing Company and Ameren Missouri were winning suppliers in Ameren Illinois' energy product RFP process. In May 2011, Marketing Company and Ameren Illinois entered into energy product agreements where Marketing Company will sell and Ameren Illinois will purchase approximately 1,747,200 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 1,840,800 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2013, and approximately 650,000 megawatthours at approximately $42 per megawatthour during the twelve months ending May 31, 2014. In May 2011, Ameren Missouri and Ameren Illinois entered into energy product agreements where Ameren Missouri will sell and Ameren Illinois will purchase approximately 16,800 megawatthours at approximately $37 per megawatthour during the twelve months ending May 31, 2012, approximately 40,800 megawatthours at approximately $29 per megawatthour during the twelve months ending May 31, 2013, and approximately 40,800 megawatthours at approximately $28 per megawatthour during the twelve months ending May 31, 2014. The 2012 and 2013 energy product agreements between Ameren Missouri and Ameren Illinois are for off-peak hours only.

Joint Ownership Agreement and Asset Transfer

ATXI and Ameren Illinois have a joint ownership agreement to construct, own, operate, and maintain certain electric transmission assets in Illinois. Under the terms of this

agreement, Ameren Illinois and ATXI are responsible for their applicable share of all costs related to the construction, operation, and maintenance of electric transmission systems. Through this joint ownership agreement, Ameren Illinois has a variable interest in ATXI, but Ameren Illinois is not the primary beneficiary. Ameren is the primary beneficiary of ATXI, and therefore consolidates ATXI. Currently, there are no construction projects or joint ownership of existing assets under this agreement.

In January 2011, ATXI repaid advances for the construction of transmission assets to Ameren Illinois in the amount of $52 million, including $3 million of accrued interest.

In March 2011, Ameren Illinois and ATXI signed an agreement to transfer, at cost, all of ATXI's construction work in progress assets related to the construction of a transmission line to Ameren Illinois for $20 million. In April 2011, Ameren Illinois paid ATXI for these assets.

Collateral Postings

Under the terms of the 2011, 2010 and 2009 Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity and energy products, and Marketing Company, as a winning supplier of capacity, financial energy swaps and energy products, may be required to post collateral. As of December 31, 2010, and June 30, 2011, there were no collateral postings required of Ameren Missouri or Marketing Company related to the 2011, 2010 and 2009 Illinois power procurement agreements.

Money Pools

See Note 3 - Credit Facility Borrowings and Liquidity for a discussion of affiliate borrowing arrangements.

The following table presents the impact on Ameren Missouri, Ameren Illinois and Genco of related party transactions for the three and six months ended June 30, 2011, and 2010. It is based primarily on the agreements discussed above and in Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K, and the money pool arrangements discussed in Note 3 - Credit Facility Borrowings and Liquidity of this report.

 

      Income Statement Line Item            Three Months     Six Months  
Agreement               AMO     AIC     Genco     AMO     AIC     Genco  

Genco and EEI power supply agreements with Marketing Company

   

Operating Revenues

      2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 485   
            2010         (a )      (a )      254        (a )      (a )      518   

Genco gas sales to Medina Valley

   

Operating Revenues

      2011         (a )      (a )      (b )      (a )      (a )      2   
            2010         (a )      (a )      -        (a )      (a )      1   

Total Operating Revenues

         2011       $ (a )    $ (a )    $ 246      $ (a )    $ (a )    $ 487   
            2010         (a )      (a )      254        (a )      (a )      519   

AIC power supply agreements with Marketing Company

   

Purchased Power

      2011       $ (a )    $ 48      $ (a )    $ (a )    $ 94      $ (a ) 
            2010         (a )      59        (a )      (a )      132        (a ) 

EEI power supply agreement with Marketing Company

   

Purchased Power

      2011         (a )      (a )      12        (a )      (a )      12   
            2010         (a )      (a )      4        (a )      (a )      4   

Total Purchased Power

         2011       $ (a )    $ 48      $ 12      $ (a )    $ 94      $ 12   
            2010         (a )      59        4        (a )      132        4   

Ameren Services support services agreement

   

Other Operations and Maintenance

      2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         32        25        6        68        53        13   

AFS support services agreement

   

Other Operations and Maintenance

      2011         (a )      (a )      (a )      (a )      (a )      (a ) 
            2010         2        (b )      (b )      3        (b )      1   

Insurance premiums(c)

   

Other Operations and Maintenance

      2011         (b )      (a )      -        (b )      (a )      -   
            2010         (b )      (a )      -        1        (a )      -   

Total Other Operations and Maintenance Expenses

         2011       $ 28      $ 21      $ 4      $ 59      $ 48      $ 10   
            2010         34        25        6        72        53        13   

Money pool borrowings (advances)

   

Interest Charges

      2011       $ -      $ -      $ (b )    $ -      $ -      $ (b ) 
            2010         -        -        (b )      -        -        (b ) 

 

(a) Not applicable.
(b) Amount less than $1 million.
(c) Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.
Commitments and Contingencies
6 Months Ended
Jun. 30, 2011
Commitments and Contingencies
Text Block 
Ameren Illinois [Member]
 
Commitments and Contingencies
Text Block 
Ameren Energy Generating Company [Member]
 
Commitments and Contingencies
Text Block 
Union Electric Company [Member]
 
Commitments and Contingencies
Text Block 
Commitments and Contingencies 

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

 

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Energy Center in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at June 30, 2011. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages     Maximum Assessments
for Single Incidents		  

Public liability and nuclear worker liability:

     

American Nuclear Insurers

    $ 375      $ -   

Pool participation

      12,219 (a)      118 (b) 
   $ 12,594 (c)    $ 118   

Property damage:

     

Nuclear Electric Insurance Ltd.

    $ 2,750 (d)    $ 23   

Replacement power:

     

Nuclear Electric Insurance Ltd.

    $ 490 (e)    $ 9   

Energy Risk Assurance Company

    $ 64 (f)    $ -   

 

(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 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 power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.'s policies, subject to an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K.

 

Our commitments for the procurement of coal have materially increased from the amounts previously disclosed in the Form 10-K. In July 2011, Ameren Missouri entered into multi-year agreements to procure ultra low-sulfur coal and the related transportation, from the Powder River Basin in Wyoming. The following table presents our total estimated coal procurement and related transportation commitments at July 19, 2011, including the July 2011 ultra low-sulfur coal and the related transportation agreements:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     669       $     1,153       $     801       $     643       $     634       $     1,651   

Ameren Missouri

      244         618         609         630         620         1,589   

Ameren's and Ameren Illinois' commitments for the procurement of purchased power have materially changed due to the 2011 RFP process administered by the IPA in the second quarter from amounts previously disclosed in Form 10-K as of December 31, 2010. See also Note 8 - Related Party Transactions in this report. The following table presents our total estimated purchased power commitments at June 30, 2011:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     178       $     200       $       314       $     129       $     55       $     826   

Ameren Illinois

      165         177         290         106         32         624   

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage facilities, and natural gas transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri and Genco, that operate coal-fired energy centers. Significant new rules already proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO2 and NO2 emissions increasing the stringency of the existing ozone national ambient air quality standard; the CSAPR, which will require further reduction of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; MACT standards for the control of hazardous air pollutants, such as mercury, metals, and acid gases from power plants; revised NSPS for particulate matter, SO2 and NOx emissions from new sources; and new regulations under the Clean Water Act, that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. Within the next year, the EPA is also expected to propose NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units as well as further reductions in the annual national ambient air quality standards for ozone and fine particulates. The EPA also plans to propose an additional rule governing air pollutant transport, but has not specified when it will issue that proposal. These new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years for Ameren, Ameren Missouri and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of plant assets. Failure to comply with environmental laws and regulations may also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our preliminary assessment of the potential impacts of the EPA's proposed regulation for CCR, the proposed MACT standard for the control of mercury and other hazardous air pollutants, the finalized CSAPR, and the revised national ambient air quality standards for SO2 and NO2 emissions as of June 30, 2011. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of new regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly national ambient air quality standards or changes to existing standards for SO2 and NO2 emissions, the final requirements under a MACT standard for the control of hazardous air pollutants such as mercury, metals, and acid gases, additional rules governing air pollutant transport, finalized regulations under the Clean Water Act, CCR being classified as hazardous, our finalized CSAPR compliance plans, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. Ameren Missouri's estimate in the table below includes the impacts of its July 2011 multi-year agreement, to procure ultra low-sulfur coal. This change in fuel mix is estimated to eliminate or postpone past 2020, $1.1 billion of Ameren Missouri's capital expenditures for pollution control equipment compared with the estimated capital expenditures included in the Form 10-K. In addition, the estimates for Genco and AERG in the table below have been updated from the estimates provided in the Form 10-K, based on the Merchant Generation segment's continued optimization of environmental compliance plans.

 

      2011      2012 - 2015      2016 - 2020      Total  

AMO(a)

    $ 40       $ 315     

-

    $ 390       $ 905     

-

    $ 1,105       $ 1,260     

-

    $ 1,535   

Genco

          125         355     

-

      435         60     

-

      75         540     

-

      635   

AERG

      10         170     

-

      210         10     

-

      15         190     

-

      235   

Ameren

    $ 175       $     840     

-

    $     1,035       $     975     

-

    $   1,195       $   1,990     

-

    $   2,405   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The following sections describe the more significant environmental rules that affect our operations.

Clean Air Act

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions. The cap-and-trade program for both annual and ozone season NOx emissions went into effect on January 1, 2009. The SO2 emissions cap-and-trade program went into effect on January 1, 2010.

In December 2008, the United States Court of Appeals for the District of Columbia remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR, which becomes effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, replaces CAIR and its applicable state rules. In the CSAPR, the EPA developed federal implementation plans for each state covered by this rule; however, each impacted state can develop its own implementation rule starting as early as 2013. The CSAPR establishes emission allowance budgets for each of the 23 states subject to the regulation, including Missouri and Illinois. With the CSAPR, the EPA abandoned CAIR's regional approach to cutting emissions and instead set a pollution budget for each of the impacted states based on the EPA's analysis of each upwind state's contribution to air quality in downwind states. For Missouri and Illinois, emission reductions are required in two phases beginning in 2012, with further reductions in 2014. The EPA estimates that by 2014, the CSAPR and other state and EPA actions will reduce SO2 emissions from power plants by 73% and NOx emissions by 54% from 2005 levels. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx program. The CSAPR is voluminous and complex and our review of the finalized regulation and its impacts is ongoing. We cannot estimate at this time whether compliance with this rule will be prohibitively expensive for any of our coal-fired energy centers or if compliance with this rule will impact the expected useful lives of our coal-fired energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments. Genco's Hutsonville and Meredosia energy centers, and a unit, specifically unit one, at AERG's E.D. Edwards energy center, are the Merchant Generation segment's least economic coal-fired facilities and the most exposed for future asset impairments. Genco's net investment in its Hutsonville and Meredosia energy centers totaled approximately $26 million and $1 million, respectively, and AERG's net investment in unit one at the E.D. Edwards energy center totaled $18 million as of June 30, 2011.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2 and also announced plans for further reductions in the annual national ambient air quality standards for ozone and fine particulates. The state of Illinois and the state of Missouri will be required to individually develop attainment plans to comply with the new ambient air quality standards. Ameren, Ameren Missouri and Genco continue to assess the impacts of these new standards. In July 2011, the EPA announced it is delaying the issuance of new annual national ambient air quality standards for ozone and fine particulates.

In March 2011, the EPA issued proposed rules under the Clean Air Act that establish a MACT standard to control mercury emissions and other hazardous air pollutants, such as acid gases, metals, and particulate matter. The MACT standard sets emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. The EPA estimates that the new rule would result in a 91% reduction in mercury emissions from coal-fired power plants. Also, the proposed rule requires reductions in hydrogen chloride emissions, which were not regulated previously, and may require continuous monitoring systems that are currently not in place. The MACT standard does not require a specific control technology to achieve the emission reductions. However, potentially applicable control technologies discussed in the proposed rule include scrubbers, dry sorbent injection, selective catalytic reduction, electrostatic precipitators, activated carbon injection and fabric filters. The MACT standard will apply to each unit at a coal-fired power plant; however, in certain circumstances, emission compliance can be averaged for the entire power plant. The EPA also proposed to revise the NSPS applicable to particulate matter, SO2 and NOx. The proposed rules are scheduled to be finalized in November 2011. Compliance is expected to be required no later than 2016 and potentially as early as late 2014. This new proposed rule is voluminous and complex, with final rules likely to be different. Ameren's review of its impact is ongoing. We cannot at this time predict whether compliance with this rule, when finalized, would be prohibitively expensive for any of our coal-fired energy centers or if compliance with this proposed rule would impact the expected useful lives of our energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning more ultra low-sulfur coal and installing additional pollution control equipment. The July 2011 purchase contract, as discussed in Other Obligations above, to procure significant volumes of lower sulfur-content coal than Ameren Missouri's energy centers currently burn will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment while still achieving required emissions levels. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next ten years and precipitator upgrades at multiple energy centers. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the emissions requirements set forth in the finalized CSAPR, the proposed MACT standard for mercury and other hazardous air pollutants, and other recently finalized or proposed EPA regulations.

Similarly, Ameren and Genco are currently evaluating the EPA's finalized CSAPR and proposed MACT standard to control mercury and other hazardous air pollutants to determine whether the new federal rules and timeline are more stringent than the existing state regulations. That review is ongoing and could require a change in the compliance plan described below. Existing Illinois state regulations already required Ameren and Genco to reduce their emissions of mercury under the MPS. Based on Ameren's and Genco's preliminary review of the proposed MACT standard, the scope of the federal standard is broader than the MPS as no exemption exists for smaller coal-fired plants. Additionally, the proposed federal rule appears more stringent than the MPS because it does not authorize compliance demonstrations based on a 12-month rolling average emission calculation as authorized under the MPS.

Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. To comply with the MPS, Genco and AERG are installing equipment designed to reduce mercury, NOx, and SO2 emissions. Genco and AERG have installed a total of three scrubbers at two energy centers and preparations for the construction of two additional scrubbers are underway at a third energy center, with completion expected in late 2013 and spring 2014. Currently, Genco's and AERG's compliance strategies and resulting estimated environmental capital expenditures also include precipitator upgrades at Genco's Joppa energy center and the inclusion of baghouse and dry sorbent injection SO2 reduction technology at AERG's E.D. Edwards energy center. Genco and AERG may also need to install additional, or optimize existing pollution control equipment to meet new emission reduction requirements under the MPS, CSAPR, or the proposed federal MACT standard as they become effective.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized or proposed environmental regulations and compliance measures could result in significant increases in capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments might not justify the required capital expenditures or their continued operation, which could result in the impairment of plant assets.

Emission Allowances

The Clean Air Act created marketable commodities called allowances under the acid rain program, the NOx budget trading program, the federal CAIR, and beginning in 2012, the CSAPR. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx programs. See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowance book values that were classified as intangible assets as of June 30, 2011, and the impairment recorded during the three and six months ended June 30, 2011.

 

Environmental regulations, including the CAIR and CSAPR, the timing of the installation of pollution control equipment, fuel mix, and the level of operations, will have a significant impact on the number of allowances required for ongoing operations. The CAIR, effective until the end of 2011, uses the acid rain program's allowances for SO2 emissions and the NOx budget trading program for both the annual and ozone season NOx allowances. The CSAPR, the CAIR replacement, however, will not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA will issue a new type of emissions allowance for each program under the CSAPR. As a result, existing SO2 allowances may be used solely for achieving compliance with the acid rain program's SO2 emission limitations. Consequently, Ameren, Ameren Missouri and Genco do not expect to use all of their existing SO2 allowances for their operations. Any unused annual and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco are analyzing the CSAPR's SO2 and NOx emission allowance allocations and trading restrictions.

Based on a preliminary review of the emission allowances granted under the CSAPR, Ameren, Ameren Missouri and Genco expect their 2012 allotment of allowances will exceed their emission levels for SO2 . In addition, Ameren Missouri expects its 2012 allotment of annual and ozone season NOx emission allowances will exceed its emission levels. Conversely, the Merchant Generation segment's expected emissions for both annual and ozone season NOx appear to exceed its 2012 allotment. Ameren, Ameren Missouri and Genco are studying their compliance options. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, install new or optimize existing pollution control equipment, limit generation, or take other actions, including the potential closure of energy centers, to achieve compliance with the CSAPR.

Global Climate Change

Initiatives to limit greenhouse gas emissions and to address climate change have been subject to consideration in the U.S. Congress. Since 2009, legislation has been passed in the U.S. House of Representatives and proposed in the Senate to reduce greenhouse gas emissions from designated sources, including coal-fired electric generation units. Many of these proposals have included economy-wide cap-and-trade programs. The reduction of greenhouse gas emissions was identified as a high priority by President Obama's administration.

Potential impacts from any climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. Ameren's analysis shows that if most versions of recently proposed climate change bills were enacted into law, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO2 as coal emits when burned to produce electricity. Therefore, climate change regulation could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy-wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

In December 2009, the EPA issued its "endangerment finding" determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act in 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized in May 2010 regulations known as the "Tailoring Rule," that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The Tailoring Rule became effective in January 2011. The rule requires any source that already has an operating permit to have greenhouse gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases of at least 75,000 tons per year, measured in CO2 equivalents, such projects could trigger permitting requirements under the NSR/Prevention of Significant Deterioration program and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources also would be required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. Separately, in December 2010, the EPA announced it would establish NSPS for greenhouse gas emissions at new and existing fossil fuel-fired power plants. The EPA has extended its deadline to issue its proposed standard for power plants, called the performance standard, until the end of September 2011, with final standards expected in 2012. It is uncertain whether reductions to greenhouse gas emissions would be required at Ameren's, Ameren Missouri's or Genco's energy centers as a result of any of the EPA's new and future rules. Legal challenges to the EPA's greenhouse gas rules have been filed. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule, particularly as it relates to power plant greenhouse gas emissions. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants, whether physical changes or changes in operations subject to the rule occur at our energy centers, and whether federal legislation that preempts the rule is passed.

Although the EPA has stated its intention to regulate greenhouse gas emissions from stationary sources, such as power plants, congressional action could block or delay that effort. In 2011, legislation was introduced in both the United States House of Representatives and Senate that would block the EPA from regulating greenhouse gas emissions from power plants and other stationary sources under the Clean Air Act. Separate legislation has also been introduced in both the United States House of Representatives and Senate that would delay the EPA's ability to regulate greenhouse gas emissions from stationary sources for two years. Although neither of these bills has been passed into law, Congress continues to discuss limiting the EPA's ability to regulate greenhouse gases.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and Genco as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's, Ameren Missouri's, and Genco's results of operations, financial position, and liquidity.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In June 2011, the United States Supreme Court in State of Connecticut v. American Electric Power rejected state efforts to impose liability for CO2 and greenhouse gases emissions under federal common law. That ruling, however, did not address whether private citizens could pursue causes of action based on state common law. In June 2011, litigation was filed in the United States District Court for the Southern District of Mississippi named Comer v. Murphy Oil (Comer), where a Mississippi property owner sued several industrial companies, including Ameren Missouri and Genco, alleging that CO2 emissions created the atmospheric conditions that intensified Hurricane Katrina. While we are unable to predict the outcome of the Comer litigation on our results of operations, financial position, and liquidity, Ameren believes that it has meritorious defenses. Numerous procedural and substantive challenges are expected in the Comer litigation.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired energy centers and our customers' costs is unknown, but any impact would probably be negative. Our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, and liquidity.

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. The request sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton energy center. All of these facilities are coal-fired energy centers. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren's coal-fired energy centers in Illinois. We completed our response to the information requests, but we are unable to predict the outcome of this matter.

 

In January 2010, Ameren Missouri received a Notice of Violation from the EPA alleging violations of the Clean Air Act's NSR and Title V programs. In the Notice of Violation, the EPA contends that various projects at Ameren Missouri's Labadie, Meramec, Rush Island, and Sioux coal-fired energy centers, dating back to the mid-1990s, triggered NSR requirements. In October 2010, the EPA supplemented and amended the Notice of Violation to include additional projects at Ameren Missouri's coal-fired energy centers. In January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In June 2011, following the filing of motions to dismiss by Ameren Missouri, the Department of Justice amended its lawsuit to include additional Rush Island projects and to correct deficiencies in the initial complaint. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the original and amended Notice of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, Ameren Missouri and Genco. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and fines or penalties. However, we are unable to predict the impact at this time.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw greater than 2 million gallons of water per day from a water body and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would need to meet mortality limits for aquatic life impinged on the plant's intake screens or reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or reduce its cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired and nuclear energy centers at Ameren, Ameren Missouri and Genco with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and Genco are currently evaluating the proposed rule and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our electric generating stations.

In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are developed based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking and has indicated that it expects to issue a proposed rule in July 2012 and finalize the rule in 2014. We are unable at this time to predict the impact of this development.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by our regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois has contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2011, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. All of these sites are in various stages of investigation, evaluation, and remediation. Based on current estimated plans, Ameren and Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2015. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC.

 

As of June 30, 2011, Ameren and Ameren Missouri own or are otherwise responsible for 10 MGP sites in Missouri and one site in Iowa. Ameren Missouri does not currently have a rate rider mechanism that permits recovery of remediation costs associated with MGP sites from utility customers. Ameren Missouri does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs.

The following table presents, as of June 30, 2011, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   121       $   199       $ 121   

Ameren Missouri

      3         4         3   

Ameren Illinois

      118         195         118   

 

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.

Ameren Illinois is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of June 30, 2011, Ameren Illinois estimated that obligation at $0.5 million to $6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2011, Ameren Illinois recorded a liability of $0.8 million to represent its best estimate of the obligation for these sites.

Ameren Missouri has responsibility for the cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri along with two other PRPs are currently performing a site investigation. As of June 30, 2011, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the cleanup of this site, which was completed in 2005. Ameren Missouri anticipates this trust fund will be sufficient to complete the remaining adjacent off-site clean-up and, therefore, has no recorded liability at June 30, 2011, related to this site.

Ameren Missouri also has a federal agency mandate to complete a site investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2011. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia's filing for bankruptcy protection. As of June 30, 2011, Ameren Missouri estimated its obligation at $0.4 million to $10 million. Ameren Missouri has a liability of $0.4 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In December 2004, AERG submitted a plan to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek energy center. In 2010, AERG closed the recycle pond system. Remediation work on the recycle pond was completed in the first quarter of 2011, and therefore no liability exists as of June 30, 2011.

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 protection laws. We are unable to determine whether such practices will result in future environmental commitments or affect our results of operations, financial position, or liquidity.

Ash Management

There has been increased activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could impact future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling, of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants to either close surface impoundments, such as ash ponds, or retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and Genco are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and Genco also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

In addition, the Illinois EPA requested that Ameren, Ameren Missouri and Genco establish groundwater monitoring plans for their ash impoundments in Illinois. Ameren and the Illinois EPA have established a framework for closure of ash ponds in Illinois, including the ash ponds at Venice, Hutsonville, and Duck Creek, when such facilities are ultimately taken out of service. In October 2010, the Illinois Pollution Control Board approved a site-specific plan for the closure of an ash pond at Genco's Hutsonville energy center. Those closure requirements include capping and covering the pond, groundwater monitoring, and the establishment of alternative groundwater standards. In May 2011, the Illinois EPA approved a site-specific closure and groundwater management plan for the ash ponds at Ameren Missouri's Venice energy center, similar to the approved plan for Hutsonville. Similar closure requirements and groundwater management plans for ash ponds at the Duck Creek energy center are being developed. Ameren, Ameren Missouri and Genco have recorded AROs, based on current laws, for the estimated costs of the retirement of their ash ponds.

Pumped-storage Hydroelectric Energy Center 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. Ameren Missouri settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri had property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance did not cover some lost electric margins or penalties paid to FERC. Ameren Missouri believes that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the upper reservoir, is approximately $208 million, which is the amount Ameren Missouri had paid as of June 30, 2011. As of June 30, 2011, Ameren Missouri had recorded expenses of $36 million, primarily in prior years, for items not covered by insurance. Ameren Missouri recorded a $172 million receivable for amounts recoverable from insurance companies under liability coverage. As of June 30, 2011, Ameren Missouri had received $104 million from insurance companies for liability claims, which reduced the insurance receivable balance subject to liability coverage to $68 million.

In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident. In January 2011, the court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. In February 2011, Ameren Missouri filed an appeal of the January ruling with the United States Court of Appeals for the Eighth Circuit, seeking the ability to pursue resolution of this dispute outside of a dispute resolution process under the terms of its coverage agreement.

Until Ameren's remaining liability insurance claims and the related litigation are resolved, we are unable to determine the total impact the breach could have on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity beyond those amounts already recognized. Ameren Missouri included certain capitalized costs associated with enhancements, or costs that could have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its recently completed electric rate case. However, in the July 2011 rate order, the MoPSC disallowed all of the capitalized costs associated with the rebuilding of the Taum Sauk energy center. As a result of the order, Ameren and Ameren Missouri will each record, in the third quarter ending September 30, 2011, a pretax charge to earnings of $89 million to reflect this disallowance. See Note 2 - Rate and Regulatory Matters for additional information about the MoPSC's July 2011 electric rate order.

 

Asbestos-related Litigation

Ameren, Ameren Missouri, Ameren Illinois and EEI have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many as 212 parties named in some pending cases and as few as two in others. However, in the cases that were pending as of June 30, 2011, the average number of parties was 78.

The claims filed against Ameren, Ameren Missouri, Ameren Illinois and Genco allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a part of the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. 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 June 30, 2011:

 

Ameren    AMO    AIC    Genco   Total(a)

5

    54    74    (b)   95

 

(a) Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
(b) As of June 30, 2011, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

At June 30, 2011, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- 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 asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are recovered from a trust fund established when Ameren acquired IP. At June 30, 2011, the trust fund balance was approximately $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is only applicable for claims that occurred within IP's historical service territory. Similarly, the rider will seek recovery only from customers within IP's historical service territory.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear the case, and the case became final. During the second quarter of 2010, Genco and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. While it is possible that Illinois will take the position that Genco and AERG do not qualify for the manufacturing exemptions and credits, we do not believe that it is probable that Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. Since the second quarter of 2010 through June 30, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $19 million and $13 million, respectively.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

Commitments and Contingencies 

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

 

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Energy Center in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at June 30, 2011. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages     Maximum Assessments
for Single Incidents		  

Public liability and nuclear worker liability:

     

American Nuclear Insurers

    $ 375      $ -   

Pool participation

      12,219 (a)      118 (b) 
   $ 12,594 (c)    $ 118   

Property damage:

     

Nuclear Electric Insurance Ltd.

    $ 2,750 (d)    $ 23   

Replacement power:

     

Nuclear Electric Insurance Ltd.

    $ 490 (e)    $ 9   

Energy Risk Assurance Company

    $ 64 (f)    $ -   

 

(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 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 power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.'s policies, subject to an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K.

 

Our commitments for the procurement of coal have materially increased from the amounts previously disclosed in the Form 10-K. In July 2011, Ameren Missouri entered into multi-year agreements to procure ultra low-sulfur coal and the related transportation, from the Powder River Basin in Wyoming. The following table presents our total estimated coal procurement and related transportation commitments at July 19, 2011, including the July 2011 ultra low-sulfur coal and the related transportation agreements:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     669       $     1,153       $     801       $     643       $     634       $     1,651   

Ameren Missouri

      244         618         609         630         620         1,589   

Ameren's and Ameren Illinois' commitments for the procurement of purchased power have materially changed due to the 2011 RFP process administered by the IPA in the second quarter from amounts previously disclosed in Form 10-K as of December 31, 2010. See also Note 8 - Related Party Transactions in this report. The following table presents our total estimated purchased power commitments at June 30, 2011:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     178       $     200       $       314       $     129       $     55       $     826   

Ameren Illinois

      165         177         290         106         32         624   

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage facilities, and natural gas transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri and Genco, that operate coal-fired energy centers. Significant new rules already proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO2 and NO2 emissions increasing the stringency of the existing ozone national ambient air quality standard; the CSAPR, which will require further reduction of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; MACT standards for the control of hazardous air pollutants, such as mercury, metals, and acid gases from power plants; revised NSPS for particulate matter, SO2 and NOx emissions from new sources; and new regulations under the Clean Water Act, that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. Within the next year, the EPA is also expected to propose NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units as well as further reductions in the annual national ambient air quality standards for ozone and fine particulates. The EPA also plans to propose an additional rule governing air pollutant transport, but has not specified when it will issue that proposal. These new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years for Ameren, Ameren Missouri and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of plant assets. Failure to comply with environmental laws and regulations may also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our preliminary assessment of the potential impacts of the EPA's proposed regulation for CCR, the proposed MACT standard for the control of mercury and other hazardous air pollutants, the finalized CSAPR, and the revised national ambient air quality standards for SO2 and NO2 emissions as of June 30, 2011. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of new regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly national ambient air quality standards or changes to existing standards for SO2 and NO2 emissions, the final requirements under a MACT standard for the control of hazardous air pollutants such as mercury, metals, and acid gases, additional rules governing air pollutant transport, finalized regulations under the Clean Water Act, CCR being classified as hazardous, our finalized CSAPR compliance plans, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. Ameren Missouri's estimate in the table below includes the impacts of its July 2011 multi-year agreement, to procure ultra low-sulfur coal. This change in fuel mix is estimated to eliminate or postpone past 2020, $1.1 billion of Ameren Missouri's capital expenditures for pollution control equipment compared with the estimated capital expenditures included in the Form 10-K. In addition, the estimates for Genco and AERG in the table below have been updated from the estimates provided in the Form 10-K, based on the Merchant Generation segment's continued optimization of environmental compliance plans.

 

      2011      2012 - 2015      2016 - 2020      Total  

AMO(a)

    $ 40       $ 315     

-

    $ 390       $ 905     

-

    $ 1,105       $ 1,260     

-

    $ 1,535   

Genco

          125         355     

-

      435         60     

-

      75         540     

-

      635   

AERG

      10         170     

-

      210         10     

-

      15         190     

-

      235   

Ameren

    $ 175       $     840     

-

    $     1,035       $     975     

-

    $   1,195       $   1,990     

-

    $   2,405   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The following sections describe the more significant environmental rules that affect our operations.

Clean Air Act

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions. The cap-and-trade program for both annual and ozone season NOx emissions went into effect on January 1, 2009. The SO2 emissions cap-and-trade program went into effect on January 1, 2010.

In December 2008, the United States Court of Appeals for the District of Columbia remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR, which becomes effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, replaces CAIR and its applicable state rules. In the CSAPR, the EPA developed federal implementation plans for each state covered by this rule; however, each impacted state can develop its own implementation rule starting as early as 2013. The CSAPR establishes emission allowance budgets for each of the 23 states subject to the regulation, including Missouri and Illinois. With the CSAPR, the EPA abandoned CAIR's regional approach to cutting emissions and instead set a pollution budget for each of the impacted states based on the EPA's analysis of each upwind state's contribution to air quality in downwind states. For Missouri and Illinois, emission reductions are required in two phases beginning in 2012, with further reductions in 2014. The EPA estimates that by 2014, the CSAPR and other state and EPA actions will reduce SO2 emissions from power plants by 73% and NOx emissions by 54% from 2005 levels. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx program. The CSAPR is voluminous and complex and our review of the finalized regulation and its impacts is ongoing. We cannot estimate at this time whether compliance with this rule will be prohibitively expensive for any of our coal-fired energy centers or if compliance with this rule will impact the expected useful lives of our coal-fired energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments. Genco's Hutsonville and Meredosia energy centers, and a unit, specifically unit one, at AERG's E.D. Edwards energy center, are the Merchant Generation segment's least economic coal-fired facilities and the most exposed for future asset impairments. Genco's net investment in its Hutsonville and Meredosia energy centers totaled approximately $26 million and $1 million, respectively, and AERG's net investment in unit one at the E.D. Edwards energy center totaled $18 million as of June 30, 2011.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2 and also announced plans for further reductions in the annual national ambient air quality standards for ozone and fine particulates. The state of Illinois and the state of Missouri will be required to individually develop attainment plans to comply with the new ambient air quality standards. Ameren, Ameren Missouri and Genco continue to assess the impacts of these new standards. In July 2011, the EPA announced it is delaying the issuance of new annual national ambient air quality standards for ozone and fine particulates.

In March 2011, the EPA issued proposed rules under the Clean Air Act that establish a MACT standard to control mercury emissions and other hazardous air pollutants, such as acid gases, metals, and particulate matter. The MACT standard sets emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. The EPA estimates that the new rule would result in a 91% reduction in mercury emissions from coal-fired power plants. Also, the proposed rule requires reductions in hydrogen chloride emissions, which were not regulated previously, and may require continuous monitoring systems that are currently not in place. The MACT standard does not require a specific control technology to achieve the emission reductions. However, potentially applicable control technologies discussed in the proposed rule include scrubbers, dry sorbent injection, selective catalytic reduction, electrostatic precipitators, activated carbon injection and fabric filters. The MACT standard will apply to each unit at a coal-fired power plant; however, in certain circumstances, emission compliance can be averaged for the entire power plant. The EPA also proposed to revise the NSPS applicable to particulate matter, SO2 and NOx. The proposed rules are scheduled to be finalized in November 2011. Compliance is expected to be required no later than 2016 and potentially as early as late 2014. This new proposed rule is voluminous and complex, with final rules likely to be different. Ameren's review of its impact is ongoing. We cannot at this time predict whether compliance with this rule, when finalized, would be prohibitively expensive for any of our coal-fired energy centers or if compliance with this proposed rule would impact the expected useful lives of our energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning more ultra low-sulfur coal and installing additional pollution control equipment. The July 2011 purchase contract, as discussed in Other Obligations above, to procure significant volumes of lower sulfur-content coal than Ameren Missouri's energy centers currently burn will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment while still achieving required emissions levels. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next ten years and precipitator upgrades at multiple energy centers. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the emissions requirements set forth in the finalized CSAPR, the proposed MACT standard for mercury and other hazardous air pollutants, and other recently finalized or proposed EPA regulations.

Similarly, Ameren and Genco are currently evaluating the EPA's finalized CSAPR and proposed MACT standard to control mercury and other hazardous air pollutants to determine whether the new federal rules and timeline are more stringent than the existing state regulations. That review is ongoing and could require a change in the compliance plan described below. Existing Illinois state regulations already required Ameren and Genco to reduce their emissions of mercury under the MPS. Based on Ameren's and Genco's preliminary review of the proposed MACT standard, the scope of the federal standard is broader than the MPS as no exemption exists for smaller coal-fired plants. Additionally, the proposed federal rule appears more stringent than the MPS because it does not authorize compliance demonstrations based on a 12-month rolling average emission calculation as authorized under the MPS.

Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. To comply with the MPS, Genco and AERG are installing equipment designed to reduce mercury, NOx, and SO2 emissions. Genco and AERG have installed a total of three scrubbers at two energy centers and preparations for the construction of two additional scrubbers are underway at a third energy center, with completion expected in late 2013 and spring 2014. Currently, Genco's and AERG's compliance strategies and resulting estimated environmental capital expenditures also include precipitator upgrades at Genco's Joppa energy center and the inclusion of baghouse and dry sorbent injection SO2 reduction technology at AERG's E.D. Edwards energy center. Genco and AERG may also need to install additional, or optimize existing pollution control equipment to meet new emission reduction requirements under the MPS, CSAPR, or the proposed federal MACT standard as they become effective.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized or proposed environmental regulations and compliance measures could result in significant increases in capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments might not justify the required capital expenditures or their continued operation, which could result in the impairment of plant assets.

Emission Allowances

The Clean Air Act created marketable commodities called allowances under the acid rain program, the NOx budget trading program, the federal CAIR, and beginning in 2012, the CSAPR. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx programs. See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowance book values that were classified as intangible assets as of June 30, 2011, and the impairment recorded during the three and six months ended June 30, 2011.

 

Environmental regulations, including the CAIR and CSAPR, the timing of the installation of pollution control equipment, fuel mix, and the level of operations, will have a significant impact on the number of allowances required for ongoing operations. The CAIR, effective until the end of 2011, uses the acid rain program's allowances for SO2 emissions and the NOx budget trading program for both the annual and ozone season NOx allowances. The CSAPR, the CAIR replacement, however, will not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA will issue a new type of emissions allowance for each program under the CSAPR. As a result, existing SO2 allowances may be used solely for achieving compliance with the acid rain program's SO2 emission limitations. Consequently, Ameren, Ameren Missouri and Genco do not expect to use all of their existing SO2 allowances for their operations. Any unused annual and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco are analyzing the CSAPR's SO2 and NOx emission allowance allocations and trading restrictions.

Based on a preliminary review of the emission allowances granted under the CSAPR, Ameren, Ameren Missouri and Genco expect their 2012 allotment of allowances will exceed their emission levels for SO2 . In addition, Ameren Missouri expects its 2012 allotment of annual and ozone season NOx emission allowances will exceed its emission levels. Conversely, the Merchant Generation segment's expected emissions for both annual and ozone season NOx appear to exceed its 2012 allotment. Ameren, Ameren Missouri and Genco are studying their compliance options. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, install new or optimize existing pollution control equipment, limit generation, or take other actions, including the potential closure of energy centers, to achieve compliance with the CSAPR.

Global Climate Change

Initiatives to limit greenhouse gas emissions and to address climate change have been subject to consideration in the U.S. Congress. Since 2009, legislation has been passed in the U.S. House of Representatives and proposed in the Senate to reduce greenhouse gas emissions from designated sources, including coal-fired electric generation units. Many of these proposals have included economy-wide cap-and-trade programs. The reduction of greenhouse gas emissions was identified as a high priority by President Obama's administration.

Potential impacts from any climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. Ameren's analysis shows that if most versions of recently proposed climate change bills were enacted into law, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO2 as coal emits when burned to produce electricity. Therefore, climate change regulation could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy-wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

In December 2009, the EPA issued its "endangerment finding" determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act in 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized in May 2010 regulations known as the "Tailoring Rule," that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The Tailoring Rule became effective in January 2011. The rule requires any source that already has an operating permit to have greenhouse gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases of at least 75,000 tons per year, measured in CO2 equivalents, such projects could trigger permitting requirements under the NSR/Prevention of Significant Deterioration program and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources also would be required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. Separately, in December 2010, the EPA announced it would establish NSPS for greenhouse gas emissions at new and existing fossil fuel-fired power plants. The EPA has extended its deadline to issue its proposed standard for power plants, called the performance standard, until the end of September 2011, with final standards expected in 2012. It is uncertain whether reductions to greenhouse gas emissions would be required at Ameren's, Ameren Missouri's or Genco's energy centers as a result of any of the EPA's new and future rules. Legal challenges to the EPA's greenhouse gas rules have been filed. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule, particularly as it relates to power plant greenhouse gas emissions. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants, whether physical changes or changes in operations subject to the rule occur at our energy centers, and whether federal legislation that preempts the rule is passed.

Although the EPA has stated its intention to regulate greenhouse gas emissions from stationary sources, such as power plants, congressional action could block or delay that effort. In 2011, legislation was introduced in both the United States House of Representatives and Senate that would block the EPA from regulating greenhouse gas emissions from power plants and other stationary sources under the Clean Air Act. Separate legislation has also been introduced in both the United States House of Representatives and Senate that would delay the EPA's ability to regulate greenhouse gas emissions from stationary sources for two years. Although neither of these bills has been passed into law, Congress continues to discuss limiting the EPA's ability to regulate greenhouse gases.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and Genco as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's, Ameren Missouri's, and Genco's results of operations, financial position, and liquidity.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In June 2011, the United States Supreme Court in State of Connecticut v. American Electric Power rejected state efforts to impose liability for CO2 and greenhouse gases emissions under federal common law. That ruling, however, did not address whether private citizens could pursue causes of action based on state common law. In June 2011, litigation was filed in the United States District Court for the Southern District of Mississippi named Comer v. Murphy Oil (Comer), where a Mississippi property owner sued several industrial companies, including Ameren Missouri and Genco, alleging that CO2 emissions created the atmospheric conditions that intensified Hurricane Katrina. While we are unable to predict the outcome of the Comer litigation on our results of operations, financial position, and liquidity, Ameren believes that it has meritorious defenses. Numerous procedural and substantive challenges are expected in the Comer litigation.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired energy centers and our customers' costs is unknown, but any impact would probably be negative. Our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, and liquidity.

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. The request sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton energy center. All of these facilities are coal-fired energy centers. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren's coal-fired energy centers in Illinois. We completed our response to the information requests, but we are unable to predict the outcome of this matter.

 

In January 2010, Ameren Missouri received a Notice of Violation from the EPA alleging violations of the Clean Air Act's NSR and Title V programs. In the Notice of Violation, the EPA contends that various projects at Ameren Missouri's Labadie, Meramec, Rush Island, and Sioux coal-fired energy centers, dating back to the mid-1990s, triggered NSR requirements. In October 2010, the EPA supplemented and amended the Notice of Violation to include additional projects at Ameren Missouri's coal-fired energy centers. In January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In June 2011, following the filing of motions to dismiss by Ameren Missouri, the Department of Justice amended its lawsuit to include additional Rush Island projects and to correct deficiencies in the initial complaint. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the original and amended Notice of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, Ameren Missouri and Genco. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and fines or penalties. However, we are unable to predict the impact at this time.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw greater than 2 million gallons of water per day from a water body and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would need to meet mortality limits for aquatic life impinged on the plant's intake screens or reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or reduce its cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired and nuclear energy centers at Ameren, Ameren Missouri and Genco with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and Genco are currently evaluating the proposed rule and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our electric generating stations.

In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are developed based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking and has indicated that it expects to issue a proposed rule in July 2012 and finalize the rule in 2014. We are unable at this time to predict the impact of this development.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by our regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois has contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2011, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. All of these sites are in various stages of investigation, evaluation, and remediation. Based on current estimated plans, Ameren and Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2015. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC.

 

As of June 30, 2011, Ameren and Ameren Missouri own or are otherwise responsible for 10 MGP sites in Missouri and one site in Iowa. Ameren Missouri does not currently have a rate rider mechanism that permits recovery of remediation costs associated with MGP sites from utility customers. Ameren Missouri does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs.

The following table presents, as of June 30, 2011, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   121       $   199       $ 121   

Ameren Missouri

      3         4         3   

Ameren Illinois

      118         195         118   

 

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.

Ameren Illinois is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of June 30, 2011, Ameren Illinois estimated that obligation at $0.5 million to $6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2011, Ameren Illinois recorded a liability of $0.8 million to represent its best estimate of the obligation for these sites.

Ameren Missouri has responsibility for the cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri along with two other PRPs are currently performing a site investigation. As of June 30, 2011, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the cleanup of this site, which was completed in 2005. Ameren Missouri anticipates this trust fund will be sufficient to complete the remaining adjacent off-site clean-up and, therefore, has no recorded liability at June 30, 2011, related to this site.

Ameren Missouri also has a federal agency mandate to complete a site investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2011. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia's filing for bankruptcy protection. As of June 30, 2011, Ameren Missouri estimated its obligation at $0.4 million to $10 million. Ameren Missouri has a liability of $0.4 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In December 2004, AERG submitted a plan to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek energy center. In 2010, AERG closed the recycle pond system. Remediation work on the recycle pond was completed in the first quarter of 2011, and therefore no liability exists as of June 30, 2011.

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 protection laws. We are unable to determine whether such practices will result in future environmental commitments or affect our results of operations, financial position, or liquidity.

Ash Management

There has been increased activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could impact future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling, of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants to either close surface impoundments, such as ash ponds, or retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and Genco are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and Genco also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

In addition, the Illinois EPA requested that Ameren, Ameren Missouri and Genco establish groundwater monitoring plans for their ash impoundments in Illinois. Ameren and the Illinois EPA have established a framework for closure of ash ponds in Illinois, including the ash ponds at Venice, Hutsonville, and Duck Creek, when such facilities are ultimately taken out of service. In October 2010, the Illinois Pollution Control Board approved a site-specific plan for the closure of an ash pond at Genco's Hutsonville energy center. Those closure requirements include capping and covering the pond, groundwater monitoring, and the establishment of alternative groundwater standards. In May 2011, the Illinois EPA approved a site-specific closure and groundwater management plan for the ash ponds at Ameren Missouri's Venice energy center, similar to the approved plan for Hutsonville. Similar closure requirements and groundwater management plans for ash ponds at the Duck Creek energy center are being developed. Ameren, Ameren Missouri and Genco have recorded AROs, based on current laws, for the estimated costs of the retirement of their ash ponds.

Pumped-storage Hydroelectric Energy Center 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. Ameren Missouri settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri had property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance did not cover some lost electric margins or penalties paid to FERC. Ameren Missouri believes that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the upper reservoir, is approximately $208 million, which is the amount Ameren Missouri had paid as of June 30, 2011. As of June 30, 2011, Ameren Missouri had recorded expenses of $36 million, primarily in prior years, for items not covered by insurance. Ameren Missouri recorded a $172 million receivable for amounts recoverable from insurance companies under liability coverage. As of June 30, 2011, Ameren Missouri had received $104 million from insurance companies for liability claims, which reduced the insurance receivable balance subject to liability coverage to $68 million.

In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident. In January 2011, the court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. In February 2011, Ameren Missouri filed an appeal of the January ruling with the United States Court of Appeals for the Eighth Circuit, seeking the ability to pursue resolution of this dispute outside of a dispute resolution process under the terms of its coverage agreement.

Until Ameren's remaining liability insurance claims and the related litigation are resolved, we are unable to determine the total impact the breach could have on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity beyond those amounts already recognized. Ameren Missouri included certain capitalized costs associated with enhancements, or costs that could have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its recently completed electric rate case. However, in the July 2011 rate order, the MoPSC disallowed all of the capitalized costs associated with the rebuilding of the Taum Sauk energy center. As a result of the order, Ameren and Ameren Missouri will each record, in the third quarter ending September 30, 2011, a pretax charge to earnings of $89 million to reflect this disallowance. See Note 2 - Rate and Regulatory Matters for additional information about the MoPSC's July 2011 electric rate order.

 

Asbestos-related Litigation

Ameren, Ameren Missouri, Ameren Illinois and EEI have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many as 212 parties named in some pending cases and as few as two in others. However, in the cases that were pending as of June 30, 2011, the average number of parties was 78.

The claims filed against Ameren, Ameren Missouri, Ameren Illinois and Genco allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a part of the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. 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 June 30, 2011:

 

Ameren    AMO    AIC    Genco   Total(a)

5

    54    74    (b)   95

 

(a) Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
(b) As of June 30, 2011, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

At June 30, 2011, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- 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 asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are recovered from a trust fund established when Ameren acquired IP. At June 30, 2011, the trust fund balance was approximately $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is only applicable for claims that occurred within IP's historical service territory. Similarly, the rider will seek recovery only from customers within IP's historical service territory.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear the case, and the case became final. During the second quarter of 2010, Genco and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. While it is possible that Illinois will take the position that Genco and AERG do not qualify for the manufacturing exemptions and credits, we do not believe that it is probable that Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. Since the second quarter of 2010 through June 30, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $19 million and $13 million, respectively.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

Commitments and Contingencies 

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

 

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Energy Center in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at June 30, 2011. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages     Maximum Assessments
for Single Incidents		  

Public liability and nuclear worker liability:

     

American Nuclear Insurers

    $ 375      $ -   

Pool participation

      12,219 (a)      118 (b) 
   $ 12,594 (c)    $ 118   

Property damage:

     

Nuclear Electric Insurance Ltd.

    $ 2,750 (d)    $ 23   

Replacement power:

     

Nuclear Electric Insurance Ltd.

    $ 490 (e)    $ 9   

Energy Risk Assurance Company

    $ 64 (f)    $ -   

 

(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 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 power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.'s policies, subject to an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K.

 

Our commitments for the procurement of coal have materially increased from the amounts previously disclosed in the Form 10-K. In July 2011, Ameren Missouri entered into multi-year agreements to procure ultra low-sulfur coal and the related transportation, from the Powder River Basin in Wyoming. The following table presents our total estimated coal procurement and related transportation commitments at July 19, 2011, including the July 2011 ultra low-sulfur coal and the related transportation agreements:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     669       $     1,153       $     801       $     643       $     634       $     1,651   

Ameren Missouri

      244         618         609         630         620         1,589   

Ameren's and Ameren Illinois' commitments for the procurement of purchased power have materially changed due to the 2011 RFP process administered by the IPA in the second quarter from amounts previously disclosed in Form 10-K as of December 31, 2010. See also Note 8 - Related Party Transactions in this report. The following table presents our total estimated purchased power commitments at June 30, 2011:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     178       $     200       $       314       $     129       $     55       $     826   

Ameren Illinois

      165         177         290         106         32         624   

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage facilities, and natural gas transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri and Genco, that operate coal-fired energy centers. Significant new rules already proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO2 and NO2 emissions increasing the stringency of the existing ozone national ambient air quality standard; the CSAPR, which will require further reduction of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; MACT standards for the control of hazardous air pollutants, such as mercury, metals, and acid gases from power plants; revised NSPS for particulate matter, SO2 and NOx emissions from new sources; and new regulations under the Clean Water Act, that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. Within the next year, the EPA is also expected to propose NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units as well as further reductions in the annual national ambient air quality standards for ozone and fine particulates. The EPA also plans to propose an additional rule governing air pollutant transport, but has not specified when it will issue that proposal. These new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years for Ameren, Ameren Missouri and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of plant assets. Failure to comply with environmental laws and regulations may also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our preliminary assessment of the potential impacts of the EPA's proposed regulation for CCR, the proposed MACT standard for the control of mercury and other hazardous air pollutants, the finalized CSAPR, and the revised national ambient air quality standards for SO2 and NO2 emissions as of June 30, 2011. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of new regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly national ambient air quality standards or changes to existing standards for SO2 and NO2 emissions, the final requirements under a MACT standard for the control of hazardous air pollutants such as mercury, metals, and acid gases, additional rules governing air pollutant transport, finalized regulations under the Clean Water Act, CCR being classified as hazardous, our finalized CSAPR compliance plans, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. Ameren Missouri's estimate in the table below includes the impacts of its July 2011 multi-year agreement, to procure ultra low-sulfur coal. This change in fuel mix is estimated to eliminate or postpone past 2020, $1.1 billion of Ameren Missouri's capital expenditures for pollution control equipment compared with the estimated capital expenditures included in the Form 10-K. In addition, the estimates for Genco and AERG in the table below have been updated from the estimates provided in the Form 10-K, based on the Merchant Generation segment's continued optimization of environmental compliance plans.

 

      2011      2012 - 2015      2016 - 2020      Total  

AMO(a)

    $ 40       $ 315     

-

    $ 390       $ 905     

-

    $ 1,105       $ 1,260     

-

    $ 1,535   

Genco

          125         355     

-

      435         60     

-

      75         540     

-

      635   

AERG

      10         170     

-

      210         10     

-

      15         190     

-

      235   

Ameren

    $ 175       $     840     

-

    $     1,035       $     975     

-

    $   1,195       $   1,990     

-

    $   2,405   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The following sections describe the more significant environmental rules that affect our operations.

Clean Air Act

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions. The cap-and-trade program for both annual and ozone season NOx emissions went into effect on January 1, 2009. The SO2 emissions cap-and-trade program went into effect on January 1, 2010.

In December 2008, the United States Court of Appeals for the District of Columbia remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR, which becomes effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, replaces CAIR and its applicable state rules. In the CSAPR, the EPA developed federal implementation plans for each state covered by this rule; however, each impacted state can develop its own implementation rule starting as early as 2013. The CSAPR establishes emission allowance budgets for each of the 23 states subject to the regulation, including Missouri and Illinois. With the CSAPR, the EPA abandoned CAIR's regional approach to cutting emissions and instead set a pollution budget for each of the impacted states based on the EPA's analysis of each upwind state's contribution to air quality in downwind states. For Missouri and Illinois, emission reductions are required in two phases beginning in 2012, with further reductions in 2014. The EPA estimates that by 2014, the CSAPR and other state and EPA actions will reduce SO2 emissions from power plants by 73% and NOx emissions by 54% from 2005 levels. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx program. The CSAPR is voluminous and complex and our review of the finalized regulation and its impacts is ongoing. We cannot estimate at this time whether compliance with this rule will be prohibitively expensive for any of our coal-fired energy centers or if compliance with this rule will impact the expected useful lives of our coal-fired energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments. Genco's Hutsonville and Meredosia energy centers, and a unit, specifically unit one, at AERG's E.D. Edwards energy center, are the Merchant Generation segment's least economic coal-fired facilities and the most exposed for future asset impairments. Genco's net investment in its Hutsonville and Meredosia energy centers totaled approximately $26 million and $1 million, respectively, and AERG's net investment in unit one at the E.D. Edwards energy center totaled $18 million as of June 30, 2011.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2 and also announced plans for further reductions in the annual national ambient air quality standards for ozone and fine particulates. The state of Illinois and the state of Missouri will be required to individually develop attainment plans to comply with the new ambient air quality standards. Ameren, Ameren Missouri and Genco continue to assess the impacts of these new standards. In July 2011, the EPA announced it is delaying the issuance of new annual national ambient air quality standards for ozone and fine particulates.

In March 2011, the EPA issued proposed rules under the Clean Air Act that establish a MACT standard to control mercury emissions and other hazardous air pollutants, such as acid gases, metals, and particulate matter. The MACT standard sets emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. The EPA estimates that the new rule would result in a 91% reduction in mercury emissions from coal-fired power plants. Also, the proposed rule requires reductions in hydrogen chloride emissions, which were not regulated previously, and may require continuous monitoring systems that are currently not in place. The MACT standard does not require a specific control technology to achieve the emission reductions. However, potentially applicable control technologies discussed in the proposed rule include scrubbers, dry sorbent injection, selective catalytic reduction, electrostatic precipitators, activated carbon injection and fabric filters. The MACT standard will apply to each unit at a coal-fired power plant; however, in certain circumstances, emission compliance can be averaged for the entire power plant. The EPA also proposed to revise the NSPS applicable to particulate matter, SO2 and NOx. The proposed rules are scheduled to be finalized in November 2011. Compliance is expected to be required no later than 2016 and potentially as early as late 2014. This new proposed rule is voluminous and complex, with final rules likely to be different. Ameren's review of its impact is ongoing. We cannot at this time predict whether compliance with this rule, when finalized, would be prohibitively expensive for any of our coal-fired energy centers or if compliance with this proposed rule would impact the expected useful lives of our energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning more ultra low-sulfur coal and installing additional pollution control equipment. The July 2011 purchase contract, as discussed in Other Obligations above, to procure significant volumes of lower sulfur-content coal than Ameren Missouri's energy centers currently burn will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment while still achieving required emissions levels. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next ten years and precipitator upgrades at multiple energy centers. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the emissions requirements set forth in the finalized CSAPR, the proposed MACT standard for mercury and other hazardous air pollutants, and other recently finalized or proposed EPA regulations.

Similarly, Ameren and Genco are currently evaluating the EPA's finalized CSAPR and proposed MACT standard to control mercury and other hazardous air pollutants to determine whether the new federal rules and timeline are more stringent than the existing state regulations. That review is ongoing and could require a change in the compliance plan described below. Existing Illinois state regulations already required Ameren and Genco to reduce their emissions of mercury under the MPS. Based on Ameren's and Genco's preliminary review of the proposed MACT standard, the scope of the federal standard is broader than the MPS as no exemption exists for smaller coal-fired plants. Additionally, the proposed federal rule appears more stringent than the MPS because it does not authorize compliance demonstrations based on a 12-month rolling average emission calculation as authorized under the MPS.

Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. To comply with the MPS, Genco and AERG are installing equipment designed to reduce mercury, NOx, and SO2 emissions. Genco and AERG have installed a total of three scrubbers at two energy centers and preparations for the construction of two additional scrubbers are underway at a third energy center, with completion expected in late 2013 and spring 2014. Currently, Genco's and AERG's compliance strategies and resulting estimated environmental capital expenditures also include precipitator upgrades at Genco's Joppa energy center and the inclusion of baghouse and dry sorbent injection SO2 reduction technology at AERG's E.D. Edwards energy center. Genco and AERG may also need to install additional, or optimize existing pollution control equipment to meet new emission reduction requirements under the MPS, CSAPR, or the proposed federal MACT standard as they become effective.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized or proposed environmental regulations and compliance measures could result in significant increases in capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments might not justify the required capital expenditures or their continued operation, which could result in the impairment of plant assets.

Emission Allowances

The Clean Air Act created marketable commodities called allowances under the acid rain program, the NOx budget trading program, the federal CAIR, and beginning in 2012, the CSAPR. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx programs. See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowance book values that were classified as intangible assets as of June 30, 2011, and the impairment recorded during the three and six months ended June 30, 2011.

 

Environmental regulations, including the CAIR and CSAPR, the timing of the installation of pollution control equipment, fuel mix, and the level of operations, will have a significant impact on the number of allowances required for ongoing operations. The CAIR, effective until the end of 2011, uses the acid rain program's allowances for SO2 emissions and the NOx budget trading program for both the annual and ozone season NOx allowances. The CSAPR, the CAIR replacement, however, will not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA will issue a new type of emissions allowance for each program under the CSAPR. As a result, existing SO2 allowances may be used solely for achieving compliance with the acid rain program's SO2 emission limitations. Consequently, Ameren, Ameren Missouri and Genco do not expect to use all of their existing SO2 allowances for their operations. Any unused annual and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco are analyzing the CSAPR's SO2 and NOx emission allowance allocations and trading restrictions.

Based on a preliminary review of the emission allowances granted under the CSAPR, Ameren, Ameren Missouri and Genco expect their 2012 allotment of allowances will exceed their emission levels for SO2 . In addition, Ameren Missouri expects its 2012 allotment of annual and ozone season NOx emission allowances will exceed its emission levels. Conversely, the Merchant Generation segment's expected emissions for both annual and ozone season NOx appear to exceed its 2012 allotment. Ameren, Ameren Missouri and Genco are studying their compliance options. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, install new or optimize existing pollution control equipment, limit generation, or take other actions, including the potential closure of energy centers, to achieve compliance with the CSAPR.

Global Climate Change

Initiatives to limit greenhouse gas emissions and to address climate change have been subject to consideration in the U.S. Congress. Since 2009, legislation has been passed in the U.S. House of Representatives and proposed in the Senate to reduce greenhouse gas emissions from designated sources, including coal-fired electric generation units. Many of these proposals have included economy-wide cap-and-trade programs. The reduction of greenhouse gas emissions was identified as a high priority by President Obama's administration.

Potential impacts from any climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. Ameren's analysis shows that if most versions of recently proposed climate change bills were enacted into law, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO2 as coal emits when burned to produce electricity. Therefore, climate change regulation could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy-wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

In December 2009, the EPA issued its "endangerment finding" determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act in 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized in May 2010 regulations known as the "Tailoring Rule," that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The Tailoring Rule became effective in January 2011. The rule requires any source that already has an operating permit to have greenhouse gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases of at least 75,000 tons per year, measured in CO2 equivalents, such projects could trigger permitting requirements under the NSR/Prevention of Significant Deterioration program and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources also would be required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. Separately, in December 2010, the EPA announced it would establish NSPS for greenhouse gas emissions at new and existing fossil fuel-fired power plants. The EPA has extended its deadline to issue its proposed standard for power plants, called the performance standard, until the end of September 2011, with final standards expected in 2012. It is uncertain whether reductions to greenhouse gas emissions would be required at Ameren's, Ameren Missouri's or Genco's energy centers as a result of any of the EPA's new and future rules. Legal challenges to the EPA's greenhouse gas rules have been filed. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule, particularly as it relates to power plant greenhouse gas emissions. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants, whether physical changes or changes in operations subject to the rule occur at our energy centers, and whether federal legislation that preempts the rule is passed.

Although the EPA has stated its intention to regulate greenhouse gas emissions from stationary sources, such as power plants, congressional action could block or delay that effort. In 2011, legislation was introduced in both the United States House of Representatives and Senate that would block the EPA from regulating greenhouse gas emissions from power plants and other stationary sources under the Clean Air Act. Separate legislation has also been introduced in both the United States House of Representatives and Senate that would delay the EPA's ability to regulate greenhouse gas emissions from stationary sources for two years. Although neither of these bills has been passed into law, Congress continues to discuss limiting the EPA's ability to regulate greenhouse gases.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and Genco as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's, Ameren Missouri's, and Genco's results of operations, financial position, and liquidity.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In June 2011, the United States Supreme Court in State of Connecticut v. American Electric Power rejected state efforts to impose liability for CO2 and greenhouse gases emissions under federal common law. That ruling, however, did not address whether private citizens could pursue causes of action based on state common law. In June 2011, litigation was filed in the United States District Court for the Southern District of Mississippi named Comer v. Murphy Oil (Comer), where a Mississippi property owner sued several industrial companies, including Ameren Missouri and Genco, alleging that CO2 emissions created the atmospheric conditions that intensified Hurricane Katrina. While we are unable to predict the outcome of the Comer litigation on our results of operations, financial position, and liquidity, Ameren believes that it has meritorious defenses. Numerous procedural and substantive challenges are expected in the Comer litigation.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired energy centers and our customers' costs is unknown, but any impact would probably be negative. Our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, and liquidity.

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. The request sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton energy center. All of these facilities are coal-fired energy centers. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren's coal-fired energy centers in Illinois. We completed our response to the information requests, but we are unable to predict the outcome of this matter.

 

In January 2010, Ameren Missouri received a Notice of Violation from the EPA alleging violations of the Clean Air Act's NSR and Title V programs. In the Notice of Violation, the EPA contends that various projects at Ameren Missouri's Labadie, Meramec, Rush Island, and Sioux coal-fired energy centers, dating back to the mid-1990s, triggered NSR requirements. In October 2010, the EPA supplemented and amended the Notice of Violation to include additional projects at Ameren Missouri's coal-fired energy centers. In January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In June 2011, following the filing of motions to dismiss by Ameren Missouri, the Department of Justice amended its lawsuit to include additional Rush Island projects and to correct deficiencies in the initial complaint. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the original and amended Notice of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, Ameren Missouri and Genco. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and fines or penalties. However, we are unable to predict the impact at this time.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw greater than 2 million gallons of water per day from a water body and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would need to meet mortality limits for aquatic life impinged on the plant's intake screens or reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or reduce its cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired and nuclear energy centers at Ameren, Ameren Missouri and Genco with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and Genco are currently evaluating the proposed rule and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our electric generating stations.

In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are developed based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking and has indicated that it expects to issue a proposed rule in July 2012 and finalize the rule in 2014. We are unable at this time to predict the impact of this development.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by our regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois has contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2011, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. All of these sites are in various stages of investigation, evaluation, and remediation. Based on current estimated plans, Ameren and Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2015. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC.

 

As of June 30, 2011, Ameren and Ameren Missouri own or are otherwise responsible for 10 MGP sites in Missouri and one site in Iowa. Ameren Missouri does not currently have a rate rider mechanism that permits recovery of remediation costs associated with MGP sites from utility customers. Ameren Missouri does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs.

The following table presents, as of June 30, 2011, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   121       $   199       $ 121   

Ameren Missouri

      3         4         3   

Ameren Illinois

      118         195         118   

 

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.

Ameren Illinois is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of June 30, 2011, Ameren Illinois estimated that obligation at $0.5 million to $6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2011, Ameren Illinois recorded a liability of $0.8 million to represent its best estimate of the obligation for these sites.

Ameren Missouri has responsibility for the cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri along with two other PRPs are currently performing a site investigation. As of June 30, 2011, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the cleanup of this site, which was completed in 2005. Ameren Missouri anticipates this trust fund will be sufficient to complete the remaining adjacent off-site clean-up and, therefore, has no recorded liability at June 30, 2011, related to this site.

Ameren Missouri also has a federal agency mandate to complete a site investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2011. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia's filing for bankruptcy protection. As of June 30, 2011, Ameren Missouri estimated its obligation at $0.4 million to $10 million. Ameren Missouri has a liability of $0.4 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In December 2004, AERG submitted a plan to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek energy center. In 2010, AERG closed the recycle pond system. Remediation work on the recycle pond was completed in the first quarter of 2011, and therefore no liability exists as of June 30, 2011.

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 protection laws. We are unable to determine whether such practices will result in future environmental commitments or affect our results of operations, financial position, or liquidity.

Ash Management

There has been increased activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could impact future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling, of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants to either close surface impoundments, such as ash ponds, or retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and Genco are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and Genco also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

In addition, the Illinois EPA requested that Ameren, Ameren Missouri and Genco establish groundwater monitoring plans for their ash impoundments in Illinois. Ameren and the Illinois EPA have established a framework for closure of ash ponds in Illinois, including the ash ponds at Venice, Hutsonville, and Duck Creek, when such facilities are ultimately taken out of service. In October 2010, the Illinois Pollution Control Board approved a site-specific plan for the closure of an ash pond at Genco's Hutsonville energy center. Those closure requirements include capping and covering the pond, groundwater monitoring, and the establishment of alternative groundwater standards. In May 2011, the Illinois EPA approved a site-specific closure and groundwater management plan for the ash ponds at Ameren Missouri's Venice energy center, similar to the approved plan for Hutsonville. Similar closure requirements and groundwater management plans for ash ponds at the Duck Creek energy center are being developed. Ameren, Ameren Missouri and Genco have recorded AROs, based on current laws, for the estimated costs of the retirement of their ash ponds.

Pumped-storage Hydroelectric Energy Center 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. Ameren Missouri settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri had property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance did not cover some lost electric margins or penalties paid to FERC. Ameren Missouri believes that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the upper reservoir, is approximately $208 million, which is the amount Ameren Missouri had paid as of June 30, 2011. As of June 30, 2011, Ameren Missouri had recorded expenses of $36 million, primarily in prior years, for items not covered by insurance. Ameren Missouri recorded a $172 million receivable for amounts recoverable from insurance companies under liability coverage. As of June 30, 2011, Ameren Missouri had received $104 million from insurance companies for liability claims, which reduced the insurance receivable balance subject to liability coverage to $68 million.

In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident. In January 2011, the court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. In February 2011, Ameren Missouri filed an appeal of the January ruling with the United States Court of Appeals for the Eighth Circuit, seeking the ability to pursue resolution of this dispute outside of a dispute resolution process under the terms of its coverage agreement.

Until Ameren's remaining liability insurance claims and the related litigation are resolved, we are unable to determine the total impact the breach could have on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity beyond those amounts already recognized. Ameren Missouri included certain capitalized costs associated with enhancements, or costs that could have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its recently completed electric rate case. However, in the July 2011 rate order, the MoPSC disallowed all of the capitalized costs associated with the rebuilding of the Taum Sauk energy center. As a result of the order, Ameren and Ameren Missouri will each record, in the third quarter ending September 30, 2011, a pretax charge to earnings of $89 million to reflect this disallowance. See Note 2 - Rate and Regulatory Matters for additional information about the MoPSC's July 2011 electric rate order.

 

Asbestos-related Litigation

Ameren, Ameren Missouri, Ameren Illinois and EEI have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many as 212 parties named in some pending cases and as few as two in others. However, in the cases that were pending as of June 30, 2011, the average number of parties was 78.

The claims filed against Ameren, Ameren Missouri, Ameren Illinois and Genco allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a part of the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. 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 June 30, 2011:

 

Ameren    AMO    AIC    Genco   Total(a)

5

    54    74    (b)   95

 

(a) Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
(b) As of June 30, 2011, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

At June 30, 2011, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- 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 asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are recovered from a trust fund established when Ameren acquired IP. At June 30, 2011, the trust fund balance was approximately $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is only applicable for claims that occurred within IP's historical service territory. Similarly, the rider will seek recovery only from customers within IP's historical service territory.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear the case, and the case became final. During the second quarter of 2010, Genco and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. While it is possible that Illinois will take the position that Genco and AERG do not qualify for the manufacturing exemptions and credits, we do not believe that it is probable that Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. Since the second quarter of 2010 through June 30, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $19 million and $13 million, respectively.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

Commitments and Contingencies 

NOTE 9 - COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

 

Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway Energy Center in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at June 30, 2011. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages     Maximum Assessments
for Single Incidents		  

Public liability and nuclear worker liability:

     

American Nuclear Insurers

    $ 375      $ -   

Pool participation

      12,219 (a)      118 (b) 
   $ 12,594 (c)    $ 118   

Property damage:

     

Nuclear Electric Insurance Ltd.

    $ 2,750 (d)    $ 23   

Replacement power:

     

Nuclear Electric Insurance Ltd.

    $ 490 (e)    $ 9   

Energy Risk Assurance Company

    $ 64 (f)    $ -   

 

(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 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 power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.'s policies, subject to an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. We have also entered into various long-term commitments for the purchase of electric capacity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K.

 

Our commitments for the procurement of coal have materially increased from the amounts previously disclosed in the Form 10-K. In July 2011, Ameren Missouri entered into multi-year agreements to procure ultra low-sulfur coal and the related transportation, from the Powder River Basin in Wyoming. The following table presents our total estimated coal procurement and related transportation commitments at July 19, 2011, including the July 2011 ultra low-sulfur coal and the related transportation agreements:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     669       $     1,153       $     801       $     643       $     634       $     1,651   

Ameren Missouri

      244         618         609         630         620         1,589   

Ameren's and Ameren Illinois' commitments for the procurement of purchased power have materially changed due to the 2011 RFP process administered by the IPA in the second quarter from amounts previously disclosed in Form 10-K as of December 31, 2010. See also Note 8 - Related Party Transactions in this report. The following table presents our total estimated purchased power commitments at June 30, 2011:

 

      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     178       $     200       $       314       $     129       $     55       $     826   

Ameren Illinois

      165         177         290         106         32         624   

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, natural gas storage facilities, and natural gas transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations governing our facilities, the EPA is developing numerous new environmental regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri and Genco, that operate coal-fired energy centers. Significant new rules already proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised ambient air quality standards for SO2 and NO2 emissions increasing the stringency of the existing ozone national ambient air quality standard; the CSAPR, which will require further reduction of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; MACT standards for the control of hazardous air pollutants, such as mercury, metals, and acid gases from power plants; revised NSPS for particulate matter, SO2 and NOx emissions from new sources; and new regulations under the Clean Water Act, that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. Within the next year, the EPA is also expected to propose NSPS and emission guidelines for greenhouse gas emissions applicable to new and existing electric generating units as well as further reductions in the annual national ambient air quality standards for ozone and fine particulates. The EPA also plans to propose an additional rule governing air pollutant transport, but has not specified when it will issue that proposal. These new regulations may be challenged with lawsuits, so the timing of their ultimate implementation is uncertain. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and/or increased operating costs over the next five to ten years for Ameren, Ameren Missouri and Genco. Actions required to ensure that our facilities and operations are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of plant assets. Failure to comply with environmental laws and regulations may also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our preliminary assessment of the potential impacts of the EPA's proposed regulation for CCR, the proposed MACT standard for the control of mercury and other hazardous air pollutants, the finalized CSAPR, and the revised national ambient air quality standards for SO2 and NO2 emissions as of June 30, 2011. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of new regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon additional federal or state requirements, regulation of greenhouse gas emissions, new hourly national ambient air quality standards or changes to existing standards for SO2 and NO2 emissions, the final requirements under a MACT standard for the control of hazardous air pollutants such as mercury, metals, and acid gases, additional rules governing air pollutant transport, finalized regulations under the Clean Water Act, CCR being classified as hazardous, our finalized CSAPR compliance plans, new technology, variations in costs of material or labor, or alternative compliance strategies, among other factors. Ameren Missouri's estimate in the table below includes the impacts of its July 2011 multi-year agreement, to procure ultra low-sulfur coal. This change in fuel mix is estimated to eliminate or postpone past 2020, $1.1 billion of Ameren Missouri's capital expenditures for pollution control equipment compared with the estimated capital expenditures included in the Form 10-K. In addition, the estimates for Genco and AERG in the table below have been updated from the estimates provided in the Form 10-K, based on the Merchant Generation segment's continued optimization of environmental compliance plans.

 

      2011      2012 - 2015      2016 - 2020      Total  

AMO(a)

    $ 40       $ 315     

-

    $ 390       $ 905     

-

    $ 1,105       $ 1,260     

-

    $ 1,535   

Genco

          125         355     

-

      435         60     

-

      75         540     

-

      635   

AERG

      10         170     

-

      210         10     

-

      15         190     

-

      235   

Ameren

    $ 175       $     840     

-

    $     1,035       $     975     

-

    $   1,195       $   1,990     

-

    $   2,405   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The following sections describe the more significant environmental rules that affect our operations.

Clean Air Act

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR required generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions. The cap-and-trade program for both annual and ozone season NOx emissions went into effect on January 1, 2009. The SO2 emissions cap-and-trade program went into effect on January 1, 2010.

In December 2008, the United States Court of Appeals for the District of Columbia remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. The CSAPR, which becomes effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions, replaces CAIR and its applicable state rules. In the CSAPR, the EPA developed federal implementation plans for each state covered by this rule; however, each impacted state can develop its own implementation rule starting as early as 2013. The CSAPR establishes emission allowance budgets for each of the 23 states subject to the regulation, including Missouri and Illinois. With the CSAPR, the EPA abandoned CAIR's regional approach to cutting emissions and instead set a pollution budget for each of the impacted states based on the EPA's analysis of each upwind state's contribution to air quality in downwind states. For Missouri and Illinois, emission reductions are required in two phases beginning in 2012, with further reductions in 2014. The EPA estimates that by 2014, the CSAPR and other state and EPA actions will reduce SO2 emissions from power plants by 73% and NOx emissions by 54% from 2005 levels. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx program. The CSAPR is voluminous and complex and our review of the finalized regulation and its impacts is ongoing. We cannot estimate at this time whether compliance with this rule will be prohibitively expensive for any of our coal-fired energy centers or if compliance with this rule will impact the expected useful lives of our coal-fired energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments. Genco's Hutsonville and Meredosia energy centers, and a unit, specifically unit one, at AERG's E.D. Edwards energy center, are the Merchant Generation segment's least economic coal-fired facilities and the most exposed for future asset impairments. Genco's net investment in its Hutsonville and Meredosia energy centers totaled approximately $26 million and $1 million, respectively, and AERG's net investment in unit one at the E.D. Edwards energy center totaled $18 million as of June 30, 2011.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2 and also announced plans for further reductions in the annual national ambient air quality standards for ozone and fine particulates. The state of Illinois and the state of Missouri will be required to individually develop attainment plans to comply with the new ambient air quality standards. Ameren, Ameren Missouri and Genco continue to assess the impacts of these new standards. In July 2011, the EPA announced it is delaying the issuance of new annual national ambient air quality standards for ozone and fine particulates.

In March 2011, the EPA issued proposed rules under the Clean Air Act that establish a MACT standard to control mercury emissions and other hazardous air pollutants, such as acid gases, metals, and particulate matter. The MACT standard sets emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. The EPA estimates that the new rule would result in a 91% reduction in mercury emissions from coal-fired power plants. Also, the proposed rule requires reductions in hydrogen chloride emissions, which were not regulated previously, and may require continuous monitoring systems that are currently not in place. The MACT standard does not require a specific control technology to achieve the emission reductions. However, potentially applicable control technologies discussed in the proposed rule include scrubbers, dry sorbent injection, selective catalytic reduction, electrostatic precipitators, activated carbon injection and fabric filters. The MACT standard will apply to each unit at a coal-fired power plant; however, in certain circumstances, emission compliance can be averaged for the entire power plant. The EPA also proposed to revise the NSPS applicable to particulate matter, SO2 and NOx. The proposed rules are scheduled to be finalized in November 2011. Compliance is expected to be required no later than 2016 and potentially as early as late 2014. This new proposed rule is voluminous and complex, with final rules likely to be different. Ameren's review of its impact is ongoing. We cannot at this time predict whether compliance with this rule, when finalized, would be prohibitively expensive for any of our coal-fired energy centers or if compliance with this proposed rule would impact the expected useful lives of our energy centers. Changes in useful life or operating cost assumptions could result in future asset impairments.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning more ultra low-sulfur coal and installing additional pollution control equipment. The July 2011 purchase contract, as discussed in Other Obligations above, to procure significant volumes of lower sulfur-content coal than Ameren Missouri's energy centers currently burn will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment while still achieving required emissions levels. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next ten years and precipitator upgrades at multiple energy centers. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the emissions requirements set forth in the finalized CSAPR, the proposed MACT standard for mercury and other hazardous air pollutants, and other recently finalized or proposed EPA regulations.

Similarly, Ameren and Genco are currently evaluating the EPA's finalized CSAPR and proposed MACT standard to control mercury and other hazardous air pollutants to determine whether the new federal rules and timeline are more stringent than the existing state regulations. That review is ongoing and could require a change in the compliance plan described below. Existing Illinois state regulations already required Ameren and Genco to reduce their emissions of mercury under the MPS. Based on Ameren's and Genco's preliminary review of the proposed MACT standard, the scope of the federal standard is broader than the MPS as no exemption exists for smaller coal-fired plants. Additionally, the proposed federal rule appears more stringent than the MPS because it does not authorize compliance demonstrations based on a 12-month rolling average emission calculation as authorized under the MPS.

Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. To comply with the MPS, Genco and AERG are installing equipment designed to reduce mercury, NOx, and SO2 emissions. Genco and AERG have installed a total of three scrubbers at two energy centers and preparations for the construction of two additional scrubbers are underway at a third energy center, with completion expected in late 2013 and spring 2014. Currently, Genco's and AERG's compliance strategies and resulting estimated environmental capital expenditures also include precipitator upgrades at Genco's Joppa energy center and the inclusion of baghouse and dry sorbent injection SO2 reduction technology at AERG's E.D. Edwards energy center. Genco and AERG may also need to install additional, or optimize existing pollution control equipment to meet new emission reduction requirements under the MPS, CSAPR, or the proposed federal MACT standard as they become effective.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized or proposed environmental regulations and compliance measures could result in significant increases in capital expenditures and operating costs. The compliance costs could be prohibitive at some of our energy centers as the expected return from these investments might not justify the required capital expenditures or their continued operation, which could result in the impairment of plant assets.

Emission Allowances

The Clean Air Act created marketable commodities called allowances under the acid rain program, the NOx budget trading program, the federal CAIR, and beginning in 2012, the CSAPR. With the CSAPR, the EPA adopted a cap-and-trade approach that allows intrastate and limited interstate trading of emission allowances with other sources within the same program, that is, either the SO2, annual NOx, or ozone season NOx programs. See Note 1 - Summary of Significant Accounting Policies for the SO2 and NOx emission allowance book values that were classified as intangible assets as of June 30, 2011, and the impairment recorded during the three and six months ended June 30, 2011.

 

Environmental regulations, including the CAIR and CSAPR, the timing of the installation of pollution control equipment, fuel mix, and the level of operations, will have a significant impact on the number of allowances required for ongoing operations. The CAIR, effective until the end of 2011, uses the acid rain program's allowances for SO2 emissions and the NOx budget trading program for both the annual and ozone season NOx allowances. The CSAPR, the CAIR replacement, however, will not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA will issue a new type of emissions allowance for each program under the CSAPR. As a result, existing SO2 allowances may be used solely for achieving compliance with the acid rain program's SO2 emission limitations. Consequently, Ameren, Ameren Missouri and Genco do not expect to use all of their existing SO2 allowances for their operations. Any unused annual and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco are analyzing the CSAPR's SO2 and NOx emission allowance allocations and trading restrictions.

Based on a preliminary review of the emission allowances granted under the CSAPR, Ameren, Ameren Missouri and Genco expect their 2012 allotment of allowances will exceed their emission levels for SO2 . In addition, Ameren Missouri expects its 2012 allotment of annual and ozone season NOx emission allowances will exceed its emission levels. Conversely, the Merchant Generation segment's expected emissions for both annual and ozone season NOx appear to exceed its 2012 allotment. Ameren, Ameren Missouri and Genco are studying their compliance options. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, install new or optimize existing pollution control equipment, limit generation, or take other actions, including the potential closure of energy centers, to achieve compliance with the CSAPR.

Global Climate Change

Initiatives to limit greenhouse gas emissions and to address climate change have been subject to consideration in the U.S. Congress. Since 2009, legislation has been passed in the U.S. House of Representatives and proposed in the Senate to reduce greenhouse gas emissions from designated sources, including coal-fired electric generation units. Many of these proposals have included economy-wide cap-and-trade programs. The reduction of greenhouse gas emissions was identified as a high priority by President Obama's administration.

Potential impacts from any climate change legislation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our diverse fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. Ameren's analysis shows that if most versions of recently proposed climate change bills were enacted into law, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO2 as coal emits when burned to produce electricity. Therefore, climate change regulation could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy-wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

In December 2009, the EPA issued its "endangerment finding" determining that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act in 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized in May 2010 regulations known as the "Tailoring Rule," that would establish new higher thresholds for regulating greenhouse gas emissions from stationary sources, such as power plants. The Tailoring Rule became effective in January 2011. The rule requires any source that already has an operating permit to have greenhouse gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases of at least 75,000 tons per year, measured in CO2 equivalents, such projects could trigger permitting requirements under the NSR/Prevention of Significant Deterioration program and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources also would be required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. Separately, in December 2010, the EPA announced it would establish NSPS for greenhouse gas emissions at new and existing fossil fuel-fired power plants. The EPA has extended its deadline to issue its proposed standard for power plants, called the performance standard, until the end of September 2011, with final standards expected in 2012. It is uncertain whether reductions to greenhouse gas emissions would be required at Ameren's, Ameren Missouri's or Genco's energy centers as a result of any of the EPA's new and future rules. Legal challenges to the EPA's greenhouse gas rules have been filed. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule, particularly as it relates to power plant greenhouse gas emissions. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants, whether physical changes or changes in operations subject to the rule occur at our energy centers, and whether federal legislation that preempts the rule is passed.

Although the EPA has stated its intention to regulate greenhouse gas emissions from stationary sources, such as power plants, congressional action could block or delay that effort. In 2011, legislation was introduced in both the United States House of Representatives and Senate that would block the EPA from regulating greenhouse gas emissions from power plants and other stationary sources under the Clean Air Act. Separate legislation has also been introduced in both the United States House of Representatives and Senate that would delay the EPA's ability to regulate greenhouse gas emissions from stationary sources for two years. Although neither of these bills has been passed into law, Congress continues to discuss limiting the EPA's ability to regulate greenhouse gases.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might deny some or all of, or defer timely recovery of, these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and Genco as well as other similarly situated electric power generators to close some coal-fired facilities earlier than planned, which could lead to possible impairment of assets and reduced revenues. As a result, mandatory limits could have a material adverse impact on Ameren's, Ameren Missouri's, and Genco's results of operations, financial position, and liquidity.

Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address damages resulting from global climate change. In June 2011, the United States Supreme Court in State of Connecticut v. American Electric Power rejected state efforts to impose liability for CO2 and greenhouse gases emissions under federal common law. That ruling, however, did not address whether private citizens could pursue causes of action based on state common law. In June 2011, litigation was filed in the United States District Court for the Southern District of Mississippi named Comer v. Murphy Oil (Comer), where a Mississippi property owner sued several industrial companies, including Ameren Missouri and Genco, alleging that CO2 emissions created the atmospheric conditions that intensified Hurricane Katrina. While we are unable to predict the outcome of the Comer litigation on our results of operations, financial position, and liquidity, Ameren believes that it has meritorious defenses. Numerous procedural and substantive challenges are expected in the Comer litigation.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, the impact on our coal-fired energy centers and our customers' costs is unknown, but any impact would probably be negative. Our costs of complying with any mandated federal or state greenhouse gas program could have a material impact on our future results of operations, financial position, and liquidity.

NSR and Clean Air Litigation

The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants should have triggered various permitting requirements and the installation of pollution control equipment.

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. The request sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton energy center. All of these facilities are coal-fired energy centers. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren's coal-fired energy centers in Illinois. We completed our response to the information requests, but we are unable to predict the outcome of this matter.

 

In January 2010, Ameren Missouri received a Notice of Violation from the EPA alleging violations of the Clean Air Act's NSR and Title V programs. In the Notice of Violation, the EPA contends that various projects at Ameren Missouri's Labadie, Meramec, Rush Island, and Sioux coal-fired energy centers, dating back to the mid-1990s, triggered NSR requirements. In October 2010, the EPA supplemented and amended the Notice of Violation to include additional projects at Ameren Missouri's coal-fired energy centers. In January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In June 2011, following the filing of motions to dismiss by Ameren Missouri, the Department of Justice amended its lawsuit to include additional Rush Island projects and to correct deficiencies in the initial complaint. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers. Litigation of this matter could take many years to resolve. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the original and amended Notice of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, Ameren Missouri and Genco. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and fines or penalties. However, we are unable to predict the impact at this time.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw greater than 2 million gallons of water per day from a water body and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would need to meet mortality limits for aquatic life impinged on the plant's intake screens or reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or reduce its cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired and nuclear energy centers at Ameren, Ameren Missouri and Genco with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and Genco are currently evaluating the proposed rule and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our electric generating stations.

In September 2009, the EPA announced its plan to revise the effluent guidelines applicable to steam electric generating units under the Clean Water Act. Effluent guidelines are national standards for wastewater discharges to surface water that are developed based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking and has indicated that it expects to issue a proposed rule in July 2012 and finalize the rule in 2014. We are unable at this time to predict the impact of this development.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by our regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois has contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of June 30, 2011, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. All of these sites are in various stages of investigation, evaluation, and remediation. Based on current estimated plans, Ameren and Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2015. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC.

 

As of June 30, 2011, Ameren and Ameren Missouri own or are otherwise responsible for 10 MGP sites in Missouri and one site in Iowa. Ameren Missouri does not currently have a rate rider mechanism that permits recovery of remediation costs associated with MGP sites from utility customers. Ameren Missouri does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs.

The following table presents, as of June 30, 2011, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   121       $   199       $ 121   

Ameren Missouri

      3         4         3   

Ameren Illinois

      118         195         118   

 

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.

Ameren Illinois is responsible for the cleanup of a former coal ash landfill in Coffeen, Illinois. As of June 30, 2011, Ameren Illinois estimated that obligation at $0.5 million to $6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2011, Ameren Illinois recorded a liability of $0.8 million to represent its best estimate of the obligation for these sites.

Ameren Missouri has responsibility for the cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri along with two other PRPs are currently performing a site investigation. As of June 30, 2011, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri has a liability of $2 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the cleanup of this site, which was completed in 2005. Ameren Missouri anticipates this trust fund will be sufficient to complete the remaining adjacent off-site clean-up and, therefore, has no recorded liability at June 30, 2011, related to this site.

Ameren Missouri also has a federal agency mandate to complete a site investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2011. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia's filing for bankruptcy protection. As of June 30, 2011, Ameren Missouri estimated its obligation at $0.4 million to $10 million. Ameren Missouri has a liability of $0.4 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In December 2004, AERG submitted a plan to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek energy center. In 2010, AERG closed the recycle pond system. Remediation work on the recycle pond was completed in the first quarter of 2011, and therefore no liability exists as of June 30, 2011.

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 protection laws. We are unable to determine whether such practices will result in future environmental commitments or affect our results of operations, financial position, or liquidity.

Ash Management

There has been increased activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could impact future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling, of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants to either close surface impoundments, such as ash ponds, or retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and Genco are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and Genco also are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted.

In addition, the Illinois EPA requested that Ameren, Ameren Missouri and Genco establish groundwater monitoring plans for their ash impoundments in Illinois. Ameren and the Illinois EPA have established a framework for closure of ash ponds in Illinois, including the ash ponds at Venice, Hutsonville, and Duck Creek, when such facilities are ultimately taken out of service. In October 2010, the Illinois Pollution Control Board approved a site-specific plan for the closure of an ash pond at Genco's Hutsonville energy center. Those closure requirements include capping and covering the pond, groundwater monitoring, and the establishment of alternative groundwater standards. In May 2011, the Illinois EPA approved a site-specific closure and groundwater management plan for the ash ponds at Ameren Missouri's Venice energy center, similar to the approved plan for Hutsonville. Similar closure requirements and groundwater management plans for ash ponds at the Duck Creek energy center are being developed. Ameren, Ameren Missouri and Genco have recorded AROs, based on current laws, for the estimated costs of the retirement of their ash ponds.

Pumped-storage Hydroelectric Energy Center 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. Ameren Missouri settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri had property and liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. Insurance did not cover some lost electric margins or penalties paid to FERC. Ameren Missouri believes that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the upper reservoir, is approximately $208 million, which is the amount Ameren Missouri had paid as of June 30, 2011. As of June 30, 2011, Ameren Missouri had recorded expenses of $36 million, primarily in prior years, for items not covered by insurance. Ameren Missouri recorded a $172 million receivable for amounts recoverable from insurance companies under liability coverage. As of June 30, 2011, Ameren Missouri had received $104 million from insurance companies for liability claims, which reduced the insurance receivable balance subject to liability coverage to $68 million.

In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident. In January 2011, the court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. In February 2011, Ameren Missouri filed an appeal of the January ruling with the United States Court of Appeals for the Eighth Circuit, seeking the ability to pursue resolution of this dispute outside of a dispute resolution process under the terms of its coverage agreement.

Until Ameren's remaining liability insurance claims and the related litigation are resolved, we are unable to determine the total impact the breach could have on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity beyond those amounts already recognized. Ameren Missouri included certain capitalized costs associated with enhancements, or costs that could have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its recently completed electric rate case. However, in the July 2011 rate order, the MoPSC disallowed all of the capitalized costs associated with the rebuilding of the Taum Sauk energy center. As a result of the order, Ameren and Ameren Missouri will each record, in the third quarter ending September 30, 2011, a pretax charge to earnings of $89 million to reflect this disallowance. See Note 2 - Rate and Regulatory Matters for additional information about the MoPSC's July 2011 electric rate order.

 

Asbestos-related Litigation

Ameren, Ameren Missouri, Ameren Illinois and EEI have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies, with as many as 212 parties named in some pending cases and as few as two in others. However, in the cases that were pending as of June 30, 2011, the average number of parties was 78.

The claims filed against Ameren, Ameren Missouri, Ameren Illinois and Genco allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a part of the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. 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 June 30, 2011:

 

Ameren    AMO    AIC    Genco   Total(a)

5

    54    74    (b)   95

 

(a) Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
(b) As of June 30, 2011, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

At June 30, 2011, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- 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 asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are recovered from a trust fund established when Ameren acquired IP. At June 30, 2011, the trust fund balance was approximately $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is only applicable for claims that occurred within IP's historical service territory. Similarly, the rider will seek recovery only from customers within IP's historical service territory.

Illinois Sales and Use Tax Exemptions and Credits

In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear the case, and the case became final. During the second quarter of 2010, Genco and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. While it is possible that Illinois will take the position that Genco and AERG do not qualify for the manufacturing exemptions and credits, we do not believe that it is probable that Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. Since the second quarter of 2010 through June 30, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $19 million and $13 million, respectively.

The Ameren Companies believe that the final disposition of these proceedings will not have a material adverse effect on their results of operations, financial position, or liquidity.

Callaway Energy Center
6 Months Ended
Jun. 30, 2011
Callaway Energy Center
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Union Electric Company [Member]
 
Callaway Energy Center
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Callaway Energy Center 

NOTE 10 - CALLAWAY ENERGY CENTER

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or one-tenth of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel (the NWF fee). Pursuant to this act, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center. Electric utility rates charged to customers provide for recovery of such costs. Ameren Missouri has sufficient installed storage capacity for spent nuclear fuel at its Callaway energy center until 2020. It has the capability for additional storage capacity through the licensed life of the energy center. In March 2010, the DOE submitted a motion to withdraw the Yucca Mountain Repository license application it filed with the NRC. In anticipation of this action, the Nuclear Energy Institute (NEI) in July 2009 formally requested that DOE promptly perform the statutorily required annual fee adequacy review and immediately suspend collection of the NWF fee. The Nuclear Waste Policy Act mandates that DOE compare the revenue generated by the NWF fee with the costs of the waste disposal program and adjust the size of the NWF fee to match the cost of the program. In the past, the cost of the program reviewed by DOE for NWF fee adequacy has been the cost of constructing and operating the Yucca Mountain Repository. The DOE declined to eliminate or reduce the NWF fee. As a result, NEI and the National Association of Regulatory Utility Commissioners (NARUC) filed petitions for review in the United States Court of Appeals for the District of Columbia Circuit seeking suspension of the NWF fee due to the DOE's motion to withdraw the application. These lawsuits were consolidated, and in December 2010 the court dismissed the petitions for review as moot (with respect to asking DOE to conduct the annual fee adequacy review) and rejected the request to suspend the fee. In March 2011, NEI and 16 of its member companies filed suit in the United States Court of Appeals for the District of Columbia Circuit again challenging the continued collection of the NWF fee. The lawsuit contends that the DOE's review of the need to continue to collect the NWF fee, which resulted in the dismissal of the earlier lawsuit as moot, is inadequate and that collection of the NWF fee should be suspended. NARUC also filed suit against the DOE in the United States Court of Appeals for the District of Columbia Circuit in March 2011, questioning the veracity of the DOE's fee adequacy assessment and seeking similar relief.

The DOE has established the Blue Ribbon Commission on America's Nuclear Future to conduct a comprehensive review of policies for managing certain components of the nuclear fuel cycle, including all alternatives for the storage, processing, and disposal of civilian and defense used nuclear fuel, high-level waste, and materials derived from nuclear activities. The Blue Ribbon Commission report will be only advisory and its draft report was submitted on July 29, 2011. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of the Callaway energy center through its currently licensed life.

In 1984, the DOE entered into a contract with Ameren Missouri to dispose of nuclear waste from its Callaway energy center. As a result of DOE's failure to build a repository for nuclear waste or otherwise fulfill its contract obligations, Ameren Missouri and other nuclear power plant owners sued DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed suit in 2004 to recover approximately $13 million in costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center's spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. In December 2010, Ameren Missouri and DOE began investigating settlement options, and in June 2011 the parties reached a settlement. The terms of the settlement include payment to Ameren Missouri of approximately $11 million for spent fuel storage and related costs through 2010, and thereafter, annual payment of such costs after they are incurred through 2013 or any other mutually agreed extension. As a result of this settlement agreement, Ameren Missouri recorded a pretax reduction of $2 million and $2 million to its depreciation and amortization and other operations and maintenance line items, respectively, on its statement of income for the three and six months ended June 30, 2011. Ameren Missouri reduced its property and plant assets by $7 million. Ameren Missouri received the DOE settlement amount in July 2011. Under the settlement, Ameren Missouri's breach of contract suit will be dismissed.

Ameren Missouri intends to submit a license extension application with the NRC to extend its Callaway energy center's operating license from 2024 to 2044. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility prior to 2020.

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 operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned based on the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 2010, 2009, and 2008. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. The latest cost study filed in September 2008 included the minor tritium contamination discovered on the Callaway energy center site, which did not result in a significant increase in the decommissioning cost estimate. Ameren Missouri expects to file a new cost study in the third quarter of 2011. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center's decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for Ameren Missouri's Callaway energy center is reported as Nuclear Decommissioning Trust Fund in Ameren's Consolidated Balance Sheet and Ameren Missouri's Balance Sheet. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory asset or regulatory liability.

Callaway Energy Center 

NOTE 10 - CALLAWAY ENERGY CENTER

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or one-tenth of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel (the NWF fee). Pursuant to this act, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center. Electric utility rates charged to customers provide for recovery of such costs. Ameren Missouri has sufficient installed storage capacity for spent nuclear fuel at its Callaway energy center until 2020. It has the capability for additional storage capacity through the licensed life of the energy center. In March 2010, the DOE submitted a motion to withdraw the Yucca Mountain Repository license application it filed with the NRC. In anticipation of this action, the Nuclear Energy Institute (NEI) in July 2009 formally requested that DOE promptly perform the statutorily required annual fee adequacy review and immediately suspend collection of the NWF fee. The Nuclear Waste Policy Act mandates that DOE compare the revenue generated by the NWF fee with the costs of the waste disposal program and adjust the size of the NWF fee to match the cost of the program. In the past, the cost of the program reviewed by DOE for NWF fee adequacy has been the cost of constructing and operating the Yucca Mountain Repository. The DOE declined to eliminate or reduce the NWF fee. As a result, NEI and the National Association of Regulatory Utility Commissioners (NARUC) filed petitions for review in the United States Court of Appeals for the District of Columbia Circuit seeking suspension of the NWF fee due to the DOE's motion to withdraw the application. These lawsuits were consolidated, and in December 2010 the court dismissed the petitions for review as moot (with respect to asking DOE to conduct the annual fee adequacy review) and rejected the request to suspend the fee. In March 2011, NEI and 16 of its member companies filed suit in the United States Court of Appeals for the District of Columbia Circuit again challenging the continued collection of the NWF fee. The lawsuit contends that the DOE's review of the need to continue to collect the NWF fee, which resulted in the dismissal of the earlier lawsuit as moot, is inadequate and that collection of the NWF fee should be suspended. NARUC also filed suit against the DOE in the United States Court of Appeals for the District of Columbia Circuit in March 2011, questioning the veracity of the DOE's fee adequacy assessment and seeking similar relief.

The DOE has established the Blue Ribbon Commission on America's Nuclear Future to conduct a comprehensive review of policies for managing certain components of the nuclear fuel cycle, including all alternatives for the storage, processing, and disposal of civilian and defense used nuclear fuel, high-level waste, and materials derived from nuclear activities. The Blue Ribbon Commission report will be only advisory and its draft report was submitted on July 29, 2011. The delayed availability of the DOE's disposal facility is not expected to adversely affect the continued operation of the Callaway energy center through its currently licensed life.

In 1984, the DOE entered into a contract with Ameren Missouri to dispose of nuclear waste from its Callaway energy center. As a result of DOE's failure to build a repository for nuclear waste or otherwise fulfill its contract obligations, Ameren Missouri and other nuclear power plant owners sued DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed suit in 2004 to recover approximately $13 million in costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center's spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. In December 2010, Ameren Missouri and DOE began investigating settlement options, and in June 2011 the parties reached a settlement. The terms of the settlement include payment to Ameren Missouri of approximately $11 million for spent fuel storage and related costs through 2010, and thereafter, annual payment of such costs after they are incurred through 2013 or any other mutually agreed extension. As a result of this settlement agreement, Ameren Missouri recorded a pretax reduction of $2 million and $2 million to its depreciation and amortization and other operations and maintenance line items, respectively, on its statement of income for the three and six months ended June 30, 2011. Ameren Missouri reduced its property and plant assets by $7 million. Ameren Missouri received the DOE settlement amount in July 2011. Under the settlement, Ameren Missouri's breach of contract suit will be dismissed.

Ameren Missouri intends to submit a license extension application with the NRC to extend its Callaway energy center's operating license from 2024 to 2044. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility prior to 2020.

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 operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned based on the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 2010, 2009, and 2008. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. The latest cost study filed in September 2008 included the minor tritium contamination discovered on the Callaway energy center site, which did not result in a significant increase in the decommissioning cost estimate. Ameren Missouri expects to file a new cost study in the third quarter of 2011. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center's decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for Ameren Missouri's Callaway energy center is reported as Nuclear Decommissioning Trust Fund in Ameren's Consolidated Balance Sheet and Ameren Missouri's Balance Sheet. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory asset or regulatory liability.

Other Comprehensive Income
6 Months Ended
Jun. 30, 2011
Other Comprehensive Income
Text Block 
Ameren Illinois [Member]
 
Other Comprehensive Income
Text Block 
Ameren Energy Generating Company [Member]
 
Other Comprehensive Income
Text Block 
Other Comprehensive Income 

NOTE 11 - OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders' equity, except those resulting from transactions with common stockholders. A reconciliation of net income to comprehensive income for the three and six months ended June 30, 2011 and 2010 is shown below for Ameren, Ameren Illinois and Genco. Ameren Missouri's comprehensive income was composed only of its net income for the three and six months ended June 30, 2011 and 2010.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:(a)

         

Net income

    $ 139      $ 155      $   213      $   261   

Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(5), $(7), $(4), and $11, respectively

      (8 )      (11 )      (6 )      17   

Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(4), $3, $(2), and $12, respectively

      7        (5 )      3        (20 ) 

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $5, $(2), and $6, respectively

      -        7        (1 )      6   

Total comprehensive income, net of taxes

    $ 138      $ 146      $ 209      $ 264   

Less: Net income attributable to noncontrolling interests, net of taxes

      1        3        4        7   

Total comprehensive income attributable to Ameren Corporation, net of taxes

    $ 137      $ 143      $ 205      $ 257   

Ameren Illinois:

         

Net income

    $ 38      $ 57      $ 72      $ 105   

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $- , $(1), and $- , respectively

      (1 )      -        (2 )      (1 ) 

Total comprehensive income, net of taxes

    $ 37      $ 57      $ 70      $ 104   

Genco:

         

Net income

    $ 13      $ 14      $ 35      $ 38   

Pension and other postretirement activity, net of income taxes (benefit) of $1, $3 , $1, and $5 , respectively

      -        5        1        4   

Total comprehensive income, net of taxes

    $ 13      $ 19      $ 36      $ 42   

Less: Net income attributable to noncontrolling interest, net of taxes

      -        1        1        2   

Total comprehensive income attributable to Genco

    $ 13      $ 18      $ 35      $ 40   

 

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

NOTE 11 - OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders' equity, except those resulting from transactions with common stockholders. A reconciliation of net income to comprehensive income for the three and six months ended June 30, 2011 and 2010 is shown below for Ameren, Ameren Illinois and Genco. Ameren Missouri's comprehensive income was composed only of its net income for the three and six months ended June 30, 2011 and 2010.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:(a)

         

Net income

    $ 139      $ 155      $   213      $   261   

Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(5), $(7), $(4), and $11, respectively

      (8 )      (11 )      (6 )      17   

Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(4), $3, $(2), and $12, respectively

      7        (5 )      3        (20 ) 

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $5, $(2), and $6, respectively

      -        7        (1 )      6   

Total comprehensive income, net of taxes

    $ 138      $ 146      $ 209      $ 264   

Less: Net income attributable to noncontrolling interests, net of taxes

      1        3        4        7   

Total comprehensive income attributable to Ameren Corporation, net of taxes

    $ 137      $ 143      $ 205      $ 257   

Ameren Illinois:

         

Net income

    $ 38      $ 57      $ 72      $ 105   

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $- , $(1), and $- , respectively

      (1 )      -        (2 )      (1 ) 

Total comprehensive income, net of taxes

    $ 37      $ 57      $ 70      $ 104   

Genco:

         

Net income

    $ 13      $ 14      $ 35      $ 38   

Pension and other postretirement activity, net of income taxes (benefit) of $1, $3 , $1, and $5 , respectively

      -        5        1        4   

Total comprehensive income, net of taxes

    $ 13      $ 19      $ 36      $ 42   

Less: Net income attributable to noncontrolling interest, net of taxes

      -        1        1        2   

Total comprehensive income attributable to Genco

    $ 13      $ 18      $ 35      $ 40   

 

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

NOTE 11 - OTHER COMPREHENSIVE INCOME

Comprehensive income includes net income as reported on the statements of income and all other changes in common stockholders' equity, except those resulting from transactions with common stockholders. A reconciliation of net income to comprehensive income for the three and six months ended June 30, 2011 and 2010 is shown below for Ameren, Ameren Illinois and Genco. Ameren Missouri's comprehensive income was composed only of its net income for the three and six months ended June 30, 2011 and 2010.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:(a)

         

Net income

    $ 139      $ 155      $   213      $   261   

Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(5), $(7), $(4), and $11, respectively

      (8 )      (11 )      (6 )      17   

Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(4), $3, $(2), and $12, respectively

      7        (5 )      3        (20 ) 

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $5, $(2), and $6, respectively

      -        7        (1 )      6   

Total comprehensive income, net of taxes

    $ 138      $ 146      $ 209      $ 264   

Less: Net income attributable to noncontrolling interests, net of taxes

      1        3        4        7   

Total comprehensive income attributable to Ameren Corporation, net of taxes

    $ 137      $ 143      $ 205      $ 257   

Ameren Illinois:

         

Net income

    $ 38      $ 57      $ 72      $ 105   

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $- , $(1), and $- , respectively

      (1 )      -        (2 )      (1 ) 

Total comprehensive income, net of taxes

    $ 37      $ 57      $ 70      $ 104   

Genco:

         

Net income

    $ 13      $ 14      $ 35      $ 38   

Pension and other postretirement activity, net of income taxes (benefit) of $1, $3 , $1, and $5 , respectively

      -        5        1        4   

Total comprehensive income, net of taxes

    $ 13      $ 19      $ 36      $ 42   

Less: Net income attributable to noncontrolling interest, net of taxes

      -        1        1        2   

Total comprehensive income attributable to Genco

    $ 13      $ 18      $ 35      $ 40   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Retirement Benefits
6 Months Ended
Jun. 30, 2011
Retirement Benefits
Text Block 
Ameren Illinois [Member]
 
Retirement Benefits
Text Block 
Ameren Energy Generating Company [Member]
 
Retirement Benefits
Text Block 
Union Electric Company [Member]
 
Retirement Benefits
Text Block 
Retirement Benefits 

NOTE 12 - RETIREMENT BENEFITS

Ameren's pension and postretirement plans are funded in compliance with income tax regulations and to achieve 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 net periodic cost for regulatory purposes or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2010, its estimated investment performance through June 30, 2011, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $110 million in each of the next five years, with aggregate estimated contributions of $470 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement net periodic cost for regulatory purposes.

 

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three and six months ended June 30, 2011, and 2010:

 

      Pension Benefits(a)     Postretirement Benefits(a)  
     Three Months     Six Months     Three Months     Six Months  
      2011     2010     2011     2010     2011     2010     2011     2010  

Service cost

    $ 18      $ 16      $ 38      $ 33      $ 5      $ 5      $ 11      $ 10   

Interest cost

      45        46        90        93        14        14        29        30   

Expected return on plan assets

      (54 )      (53 )      (108 )      (106 )      (13 )      (14 )      (27 )      (28 ) 

Amortization of:

                 

Transition obligation

      -        -        -        -        1        1        1        1   

Prior service cost (benefit)

     (1 )      2        (1 )      4        (2 )      (2 )      (4 )      (4 ) 

Actuarial loss (gain)

     10        4        21        9        1        (1 )      2        1   

Net periodic cost

    $ 18      $ 15      $ 40      $ 33      $ 6      $ 3      $ 12      $ 10   

 

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

Ameren Missouri, Ameren Illinois and Genco are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and six months ended June 30, 2011, and 2010:

 

      Pension Costs      Postretirement Costs  
     Three Months      Six Months      Three Months      Six Months  
      2011      2010      2011      2010      2011      2010      2011      2010  

Ameren Missouri

    $ 12       $ 9       $ 26       $ 21       $ 2       $ 2       $ 5       $ 5   

Ameren Illinois

      3         4         8         6         4         1         6         4   

Genco

      3         2         5         5         -         -         1         1   

Other

      -         -         1         1         -         -         -         -   

Ameren(a)

    $ 18       $ 15       $ 40       $ 33       $ 6       $ 3       $ 12       $ 10   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Retirement Benefits 

NOTE 12 - RETIREMENT BENEFITS

Ameren's pension and postretirement plans are funded in compliance with income tax regulations and to achieve 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 net periodic cost for regulatory purposes or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2010, its estimated investment performance through June 30, 2011, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $110 million in each of the next five years, with aggregate estimated contributions of $470 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement net periodic cost for regulatory purposes.

 

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three and six months ended June 30, 2011, and 2010:

 

      Pension Benefits(a)     Postretirement Benefits(a)  
     Three Months     Six Months     Three Months     Six Months  
      2011     2010     2011     2010     2011     2010     2011     2010  

Service cost

    $ 18      $ 16      $ 38      $ 33      $ 5      $ 5      $ 11      $ 10   

Interest cost

      45        46        90        93        14        14        29        30   

Expected return on plan assets

      (54 )      (53 )      (108 )      (106 )      (13 )      (14 )      (27 )      (28 ) 

Amortization of:

                 

Transition obligation

      -        -        -        -        1        1        1        1   

Prior service cost (benefit)

     (1 )      2        (1 )      4        (2 )      (2 )      (4 )      (4 ) 

Actuarial loss (gain)

     10        4        21        9        1        (1 )      2        1   

Net periodic cost

    $ 18      $ 15      $ 40      $ 33      $ 6      $ 3      $ 12      $ 10   

 

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

Ameren Missouri, Ameren Illinois and Genco are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and six months ended June 30, 2011, and 2010:

 

      Pension Costs      Postretirement Costs  
     Three Months      Six Months      Three Months      Six Months  
      2011      2010      2011      2010      2011      2010      2011      2010  

Ameren Missouri

    $ 12       $ 9       $ 26       $ 21       $ 2       $ 2       $ 5       $ 5   

Ameren Illinois

      3         4         8         6         4         1         6         4   

Genco

      3         2         5         5         -         -         1         1   

Other

      -         -         1         1         -         -         -         -   

Ameren(a)

    $ 18       $ 15       $ 40       $ 33       $ 6       $ 3       $ 12       $ 10   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Retirement Benefits 

NOTE 12 - RETIREMENT BENEFITS

Ameren's pension and postretirement plans are funded in compliance with income tax regulations and to achieve 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 net periodic cost for regulatory purposes or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2010, its estimated investment performance through June 30, 2011, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $110 million in each of the next five years, with aggregate estimated contributions of $470 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement net periodic cost for regulatory purposes.

 

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three and six months ended June 30, 2011, and 2010:

 

      Pension Benefits(a)     Postretirement Benefits(a)  
     Three Months     Six Months     Three Months     Six Months  
      2011     2010     2011     2010     2011     2010     2011     2010  

Service cost

    $ 18      $ 16      $ 38      $ 33      $ 5      $ 5      $ 11      $ 10   

Interest cost

      45        46        90        93        14        14        29        30   

Expected return on plan assets

      (54 )      (53 )      (108 )      (106 )      (13 )      (14 )      (27 )      (28 ) 

Amortization of:

                 

Transition obligation

      -        -        -        -        1        1        1        1   

Prior service cost (benefit)

     (1 )      2        (1 )      4        (2 )      (2 )      (4 )      (4 ) 

Actuarial loss (gain)

     10        4        21        9        1        (1 )      2        1   

Net periodic cost

    $ 18      $ 15      $ 40      $ 33      $ 6      $ 3      $ 12      $ 10   

 

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

Ameren Missouri, Ameren Illinois and Genco are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and six months ended June 30, 2011, and 2010:

 

      Pension Costs      Postretirement Costs  
     Three Months      Six Months      Three Months      Six Months  
      2011      2010      2011      2010      2011      2010      2011      2010  

Ameren Missouri

    $ 12       $ 9       $ 26       $ 21       $ 2       $ 2       $ 5       $ 5   

Ameren Illinois

      3         4         8         6         4         1         6         4   

Genco

      3         2         5         5         -         -         1         1   

Other

      -         -         1         1         -         -         -         -   

Ameren(a)

    $ 18       $ 15       $ 40       $ 33       $ 6       $ 3       $ 12       $ 10   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Retirement Benefits 

NOTE 12 - RETIREMENT BENEFITS

Ameren's pension and postretirement plans are funded in compliance with income tax regulations and to achieve 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 net periodic cost for regulatory purposes or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2010, its estimated investment performance through June 30, 2011, and its pension funding policy, Ameren expects to make annual contributions of $75 million to $110 million in each of the next five years, with aggregate estimated contributions of $470 million. These amounts are estimates which may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement net periodic cost for regulatory purposes.

 

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three and six months ended June 30, 2011, and 2010:

 

      Pension Benefits(a)     Postretirement Benefits(a)  
     Three Months     Six Months     Three Months     Six Months  
      2011     2010     2011     2010     2011     2010     2011     2010  

Service cost

    $ 18      $ 16      $ 38      $ 33      $ 5      $ 5      $ 11      $ 10   

Interest cost

      45        46        90        93        14        14        29        30   

Expected return on plan assets

      (54 )      (53 )      (108 )      (106 )      (13 )      (14 )      (27 )      (28 ) 

Amortization of:

                 

Transition obligation

      -        -        -        -        1        1        1        1   

Prior service cost (benefit)

     (1 )      2        (1 )      4        (2 )      (2 )      (4 )      (4 ) 

Actuarial loss (gain)

     10        4        21        9        1        (1 )      2        1   

Net periodic cost

    $ 18      $ 15      $ 40      $ 33      $ 6      $ 3      $ 12      $ 10   

 

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

Ameren Missouri, Ameren Illinois and Genco are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and six months ended June 30, 2011, and 2010:

 

      Pension Costs      Postretirement Costs  
     Three Months      Six Months      Three Months      Six Months  
      2011      2010      2011      2010      2011      2010      2011      2010  

Ameren Missouri

    $ 12       $ 9       $ 26       $ 21       $ 2       $ 2       $ 5       $ 5   

Ameren Illinois

      3         4         8         6         4         1         6         4   

Genco

      3         2         5         5         -         -         1         1   

Other

      -         -         1         1         -         -         -         -   

Ameren(a)

    $ 18       $ 15       $ 40       $ 33       $ 6       $ 3       $ 12       $ 10   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Segment Information
Segment Information

NOTE 13 - SEGMENT INFORMATION

Ameren has three reportable segments: Ameren Missouri, Ameren Illinois, and Merchant Generation. The Ameren Missouri segment for Ameren includes all the operations of Ameren Missouri's business as described in Note 1 - Summary of Significant Accounting Policies. The Ameren Illinois Regulated Segment for Ameren includes all of the operations of Ameren Illinois' business as described in Note 1 - Summary of Significant Accounting Policies. The Merchant Generation segment for Ameren consists primarily of the operations or activities of Genco, including EEI, AERG, Medina Valley and Marketing Company. The category called Other primarily includes Ameren parent company activities, Ameren Services, and ATXI.

The following table presents information about the reported revenues and specified items included in Ameren's net income for the three and six months ended June 30, 2011, and 2010, and total assets as of June 30, 2011, and December 31, 2010.

 

                                                 
Three Months    Ameren
Missouri		      Ameren
Illinois		      Merchant
Generation		     Other     Intersegment
Eliminations		     Consolidated  

2011:

                                                   

External revenues

    $ 814       $ 619       $ 347      $ 1      $ -      $ 1,781   

Intersegment revenues

      8         4         49        -        (61 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      90         37         15        (4 )      -        138   

2010:

                                                   

External revenues

    $ 756       $ 644       $ 325      $ -      $ -      $ 1,725   

Intersegment revenues

      5         3         60        3        (71 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      113         46         (2 )      (5 )      -        152   
Six Months                                             

2011:

                                                   

External revenues

    $ 1,581       $ 1,424       $ 679      $ 1      $ -      $ 3,685   

Intersegment revenues

      13         7         96        1        (117 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      111         70         35        (7 )      -        209   

2010:

                                                   

External revenues

    $ 1,433       $ 1,553       $ 679      $ -      $ -      $ 3,665   

Intersegment revenues

      10         5         134        6        (155 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      140         81         42        (9 )      -        254   
Six Months    Ameren
Missouri		      Ameren
Illinois		      Merchant
Generation		     Other     Intersegment
Eliminations		     Consolidated  

As of June 30, 2011:

                                                   

Total assets

    $ 12,527       $ 7,154       $ 3,861      $  1,324      $ (1,475 )    $ 23,391   

As of December 31, 2010:

                                                   

Total assets

    $ 12,504       $ 7,406       $ 3,934      $ 1,354      $ (1,683 )    $ 23,515   

 

(a) Represents net income (loss) available to common stockholders.
Discontinued Operations
6 Months Ended
Jun. 30, 2011
Discontinued Operations
Text Block 
Ameren Illinois [Member]
 
Discontinued Operations
Text Block 
Discontinued Operations 

NOTE 14 - DISCONTINUED OPERATIONS

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company.

Ameren Illinois has segregated AERG's operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. Effective October 1, 2010, Ameren Illinois does not have any significant continuing involvement in the operations of AERG. For Ameren's financial statements, AERG's results of operations remain classified as continuing operations. The table below summarizes the operating results of Ameren Illinois' former merchant generation subsidiary, AERG, classified as discontinued operations in Ameren Illinois' statement of income for the three and six months ended June 30, 2010:

 

      2010  
      Three
Months		      Six
Months		  

Operating revenues

    $ 85       $ 176   

Operating expenses

      67         134   

Operating income

      18         42   

Other income

      1         1   

Interest charges

      5         10   

Income taxes

      5         12   

Income from discontinued operations, net of tax

    $ 9       $ 21   
Discontinued Operations 

NOTE 14 - DISCONTINUED OPERATIONS

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company.

Ameren Illinois has segregated AERG's operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. Effective October 1, 2010, Ameren Illinois does not have any significant continuing involvement in the operations of AERG. For Ameren's financial statements, AERG's results of operations remain classified as continuing operations. The table below summarizes the operating results of Ameren Illinois' former merchant generation subsidiary, AERG, classified as discontinued operations in Ameren Illinois' statement of income for the three and six months ended June 30, 2010:

 

      2010  
      Three
Months		      Six
Months		  

Operating revenues

    $ 85       $ 176   

Operating expenses

      67         134   

Operating income

      18         42   

Other income

      1         1   

Interest charges

      5         10   

Income taxes

      5         12   

Income from discontinued operations, net of tax

    $ 9       $ 21   
Summary of Significant Accounting Policies (Policy)
General 

On October 1, 2010, Ameren, CIPS, CILCO, IP, AERG and Resources Company completed a two-step corporate internal reorganization. The first step of the reorganization was the Ameren Illinois Merger. Upon consummation of the Ameren Illinois Merger, the separate legal existence of CILCO and IP terminated. The second step of the reorganization involved the distribution of AERG stock from Ameren Illinois to Ameren and the subsequent contribution by Ameren of the AERG stock to Resources Company. The Ameren Illinois Merger and the distribution of AERG stock were accounted for as transactions between entities under common control. In accordance with authoritative accounting guidance, assets and liabilities transferred between entities under common control were accounted for at the historical cost basis of the common parent, Ameren, as if the transfer had occurred at the beginning of the earliest reporting period presented. Ameren's historical cost basis in Ameren Illinois included purchase accounting adjustments related to Ameren's acquisition of CILCORP in 2003. Ameren Illinois accounted for the AERG distribution as a spinoff. Ameren Illinois transferred AERG to Ameren based on AERG's carrying value. Ameren Illinois has segregated AERG's operating results and cash flows and presented them separately as discontinued operations in its consolidated statement of income and consolidated statement of cash flows, respectively, for all periods presented prior to October 1, 2010, in this report. For Ameren's financial statements, AERG's results of operations remain classified as continuing operations. See Note 14 - Discontinued Operations for additional information.

Consolidation 

The financial statements of Ameren, Ameren Illinois and Genco are prepared on a consolidated basis. Ameren Missouri has no subsidiaries, and therefore its financial statements were not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K.

Earnings Per Share 

Earnings Per Share

There were no material differences between Ameren's basic and diluted earnings per share amounts for the three months and six months ended June 30, 2011, and 2010. The number of restricted stock shares and performance share units outstanding had an immaterial impact on earnings per share.

Long-term Incentive Plan 

The fair value of each share unit awarded in January 2011 under the 2006 Plan was determined to be $31.41. That amount was based on Ameren's closing common share price of $28.19 at December 31, 2010, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2011. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 1.08%, volatility of 22% to 36% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $4 million and $2 million for the three months ended June 30, 2011, and 2010, respectively, and a related tax benefit of $2 million and $1 million for the three months ended June 30, 2011, and 2010, respectively. Ameren recorded compensation expense of $7 million for each of the six-month periods ended June 30, 2011, and 2010, respectively, and a related tax benefit of $3 million for each of the six-month periods ended June 30, 2011, and 2010, respectively. As of June 30, 2011, total compensation expense of $27 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 22 months.

Accounting Changes and Other Matters 

Accounting Changes

Disclosures about Fair Value Measurements

See Note 7 - Fair Value Measurements for recently adopted guidance on fair value measurements.

In May 2011, FASB issued authoritative guidance regarding fair value measurements. The guidance amends the disclosure requirements for fair value measurements in order to align the principles for fair value measurements and the related disclosure requirements under GAAP and International Financial Reporting Standards. The amendments will not impact the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

 

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance with respect to comprehensive income will not impact the Ameren Companies' results of operations, financial positions, or liquidity or the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amended guidance will only change the presentation of comprehensive income in the financial statements. The new accounting guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This guidance will become effective for the Ameren Companies for periods starting after December 31, 2011.

Goodwill and Intangible Assets 

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of June 30, 2011, Ameren's and Ameren Illinois' goodwill related to the acquisition of IP in 2004 and the acquisition of CILCORP in 2003. We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events or changes in circumstances indicate that the asset might be impaired.

Intangible Assets. Ameren, Ameren Missouri and Genco classify emission allowances and renewable energy credits as intangible assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired.

In July 2011, the EPA issued the CSAPR, which will create new allowances for SO2 and NOx emissions, thereby restricting the use of existing SO2 and NOx allowances to the acid rain program and NOx budget trading program, respectively. In anticipation of the CSAPR announcement, observable market prices for existing emission allowances declined materially. Consequently, during the second quarter of 2011, Ameren and Genco recorded a noncash pretax impairment charge to other operations and maintenance expense of $2 million and $1 million, respectively. Ameren Missouri recorded a $1 million impairment of its SO2 emission allowances by reducing a previously established regulatory liability relating to the SO2 emission allowances, which had no impact to earnings. See Note 9 - Commitments and Contingencies for additional information on emission allowances and the CSAPR.

Emission allowances are charged to fuel expense as they are used in operations. The following table presents amortization expense based on usage of emission allowances, net of gains from emission allowance sales for Ameren, Ameren Missouri and Genco during the three and six months ended June 30, 2011, and 2010. The table below does not include the intangible asset impairment charges referenced above.

 

      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren(a)

    $ 1      $ 7      $ 2      $ 10   

AMO

      -        (b )      -        (b ) 

Genco(a)

      1        5        2        8   

AERG(a)

      (b )      2        (b )      2   

 

(a) Includes allowances consumed that were recorded through purchase accounting.
(b) Less than $1 million.

At June 30, 2011, Ameren's and Ameren Missouri's intangible assets also included renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits as of June 30, 2011, was $3 million.

Excise Taxes 

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and natural gas customer bills and Ameren Illinois natural gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes on the statement of income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Taxes Accrued on the balance sheet. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses - Taxes Other than Income Taxes for the three and six months ended June 30, 2011 and 2010:

 

      Three Months      Six Months  
      2011      2010      2011      2010  

Ameren

    $ 44       $ 44       $ 95       $ 90   

AMO

      34         33         63         58   

AIC

      10         11         32         32   
Uncertain Tax Positions 

Uncertain Tax Positions

The amount of unrecognized tax benefits as of June 30, 2011, was $198 million, $146 million, $33 million, and $16 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2011, that would impact the effective tax rate, if recognized, was $2 million, $2 million, $(1) million and $1 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively.

In the second quarter of 2011, final settlement for the 2005 and 2006 years was reached with the Internal Revenue Service, which resulted in the reduction of uncertain tax liabilities by $39 million, $17 million, $12 million and $4 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. Ameren's federal income tax returns for the years 2007 through 2009 are before the Appeals Office of the Internal Revenue Service.

State income tax returns are generally subject to examination for a period of three years after filing of the return. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states.

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their results of operations, financial position or liquidity.

Summary of Significant Accounting Policies (Tables)
Long-Term Incentive Plan 
      Performance Share Units(a)      Restricted Shares(b)  
      Share
Units		    

Weighted-average
Fair Value Per Unit

at Grant Date

      Shares    

Weighted-average
Fair Value Per Share

at Grant Date

  

Nonvested at January 1, 2011

      1,142,768      $ 23.96         83,154      $ 49.87   

Granted(c)

      731,962        31.41         -        -   

Dividends

      -        -         518        28.48   

Forfeitures

      (10,261 )      26.14         (560 )      50.45   

Vested(d)

      (131,343 )      30.67         (63,574 )      49.47   

Nonvested at June 30, 2011

      1,733,126      $ 26.58         19,538      $ 51.21   

 

(a) Granted under the 2006 Plan.
(b) Granted under the 1998 Plan.
(c) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2011 under the 2006 Plan.
(d) Shares/units vested due to Ameren attainment of performance goals and 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 for Intangible Assets 
      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren(a)

    $ 1      $ 7      $ 2      $ 10   

AMO

      -        (b )      -        (b ) 

Genco(a)

      1        5        2        8   

AERG(a)

      (b )      2        (b )      2   

 

(a) Includes allowances consumed that were recorded through purchase accounting.
(b) Less than $1 million.
Schedule of Excise Taxes 
      Three Months      Six Months  
      2011      2010      2011      2010  

Ameren

    $ 44       $ 44       $ 95       $ 90   

AMO

      34         33         63         58   

AIC

      10         11         32         32   
Schedule of Noncontrolling Interest 
      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:

         

Noncontrolling interest, beginning of period

    $ 155      $ 206      $   154      $   204   

Net income attributable to noncontrolling interest

      1        3        4        7   

Dividends paid to noncontrolling interest holders

      (1 )      (3 )      (3 )      (5 ) 

Noncontrolling interest, end of period

    $ 155      $ 206      $ 155      $ 206   

Genco:

         

Noncontrolling interest, beginning of period

    $ 12      $ 10      $ 11      $ 9   

Net income attributable to noncontrolling interest

      -        1        1        2   

Noncontrolling interest, end of period

    $ 12      $ 11      $ 12      $ 11   
Rate and Regulatory Matters (Tables)
Schedule of Regulatory Assets and Liabilities
Regulatory Assets and Liabilities   

Regulatory Asset

(Liability) Balance
at June 30, 2011

    

Recovery Period

Ends

  

Demand-side costs(a)

    $ 33        July 2017   

Construction accounting for pollution control equipment(a)

      25        July 2038   

SO2 emissions allowances sales tracker(b)

      8        July 2013   

FERC-ordered MISO resettlements(b)

      2        July 2013   

2006 Storm costs(b)

      1        July 2013   

Vegetation management and infrastructure inspection(b)

      (3 )      July 2013   

Pension and postretirement benefit cost tracker for 2010 costs(a)

      (11 )      July 2016   

Total

    $ 55           

 

(a) Recovery period first established in the MoPSC's July 2011 rate order.
(b) Previous recovery period was extended.
Credit Facility Borrowings and Liquidity (Tables)
Borrowing Activity on Credit Agreements
2010 Missouri Credit Agreement ($800 million)    Ameren (Parent)     Ameren Missouri     Total  

Average daily borrowings outstanding during 2011

    $ 181      $ -      $ 181   

Outstanding credit facility borrowings at period end

      200        -        200   

Weighted-average interest rate during 2011

      2.31 %      -        2.31 % 

Peak credit facility borrowings during 2011(a)

    $ 340      $ -      $ 340   

Peak interest rate during 2011

      4.30 %      -        4.30 % 
      
2010 Genco Credit Agreement ($500 million)      Ameren (Parent)        Genco        Total   

Average daily borrowings outstanding during 2011

    $ -      $ 83      $ 83   

Outstanding credit facility borrowings at period end

      -        -        -   

Weighted-average interest rate during 2011

      -        2.30 %      2.30 % 

Peak credit facility borrowings during 2011(a)

    $ -      $ 100      $ 100   

Peak interest rate during 2011

      -        2.31 %      2.31 % 

 

(a) The timing of peak credit facility borrowings varies by company and therefore the amounts presented by company might not equal the total peak credit facility borrowings for the period. The simultaneous peak credit facility borrowings by the Ameren Companies under all credit facilities during the first six months of 2011 were $440 million.
Other Income and Expenses (Tables)
Other Income and Expenses
      Three Months      Six Months  
          2011              2010              2011              2010      

Ameren:(a)

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 13       $ 15       $ 26   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      1         1         2         2   

Other

      -         3         2         4   

Total miscellaneous income

    $ 17       $ 24       $ 33       $ 46   

Miscellaneous expense:

            

Donations

    $ 1       $ 1       $ 3       $ 3   

Other

      4         1         7         6   

Total miscellaneous expense

    $ 5       $ 2       $ 10       $ 9   

Ameren Missouri:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ 9       $ 12       $ 14       $ 25   

Interest income on industrial development revenue bonds

      7         7         14         14   

Interest and dividend income

      -         1         1         1   

Other

      -         -         -         1   

Total miscellaneous income

    $ 16       $ 20       $ 29       $ 41   

Miscellaneous expense:

            

Donations

    $ 1       $ -       $ 2       $ 1   

Other

      2         1         4         2   

Total miscellaneous expense

    $ 3       $ 1       $ 6       $ 3   

Ameren Illinois:

            

Miscellaneous income:

            

Allowance for equity funds used during construction

    $ -       $ 1       $ 1       $ 1   

Interest and dividend income

      -         -         -         1   

Other

      1         1         2         2   

Total miscellaneous income

    $ 1       $ 2       $ 3       $ 4   

Miscellaneous expense:

            

Donations

    $ -       $ 1       $ -       $ 1   

Other

      1         -         2         3   

Total miscellaneous expense

    $ 1       $ 1       $ 2       $ 4   

Genco:

            

Miscellaneous income:

            

Other

    $ -       $ 1       $ -       $ 1   

Total miscellaneous income

    $ -       $ 1       $ -       $ 1   

Miscellaneous expense:

            

Other

    $ -       $ -       $ -       $ 1   

Total miscellaneous expense

    $ -       $ -       $ -       $ 1   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Derivative Financial Instruments (Tables)
6 Months Ended
Jun. 30, 2011
Open Gross Derivative Volumes by Commodity Type
Text Block 
Derivative Instruments Carrying Value
Text Block 
Cumulative Pretax Net Gains (Losses) on All Derivative Instruments Reported in the Statement of Financial Position
Text Block 
Cash Collateral Held From Counterparties
Text Block 
Potential Loss on Counterparty Exposures
Text Block 
Derivative Instruments With Credit Risk-Related Contingent Features
Text Block 
Cash Flow Hedges
Text Block 
Other Derivatives
Text Block 
Derivatives that Qualify for Regulatory Deferral
Text Block 
Customer Concentration Risk [Member]
 
Maximum Exposure If Counterparties Fail To Perform on Contracts
Text Block 
Open Gross Derivative Volumes by Commodity Type 
                                                                 
      Quantity (in millions, except as indicated)  
Commodity   

NPNS

Contracts(a)

     Cash Flow
Hedges(b)		     Other
Derivatives(c)		     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2011     2010     2011     2010     2011     2010     2011     2010  

Coal (in tons)

                                                                 

AMO

      36        46        (e )      (e )      (e )      (e )      (e )      (e ) 

Genco

      24        21        (e )      (e )      (e )      (e )      (e )      (e ) 

Other(f)

      6        6        (e )      (e )      (e )      (e )      (e )      (e ) 

Ameren

                     66                        73                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Heating oil (in gallons)

                                                                 

AMO

      (e )      (e )      (e )      (e )      (e )      (e )      62        80   

Genco

      (e )      (e )      (e )      (e )      31        43        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      9        12        (e )      (e ) 

Ameren

     (e )      (e )      (e )      (e )      40        55        62        80   

Natural gas (in mmbtu)

                                                                 

AMO

      10        13        (e )      (e )      3        2        21        21   

AIC

      62        85        (e )      (e )      (e )      (e )      175        173   

Genco

      (e )      (e )      (e )      (e )      3        3        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      20        16        (e )      (e ) 

Ameren

     72        98        (e )      (e )      26        21        196        194   

Power (in megawatthours)

                                                                 

AMO

      2        2        (e )      (e )      1        1        3        5   

AIC

      12        (e )      (e )      (e )      (e )      (e )      31        26   

Genco

      (e )      (e )      (e )      (e )      2        3        (e )      (e ) 

Other(f)

      65        61        21        2        51        57        (14 )      (13 ) 

Ameren

     79        63        21        2        54        61        20        18   

Uranium (pounds in thousands)

                                                                 

AMO

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

Ameren

      5,710        5,810        (e )      (e )      (e )      (e )      458        185   

 

(a) Contracts through December 2014, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of June 30, 2011.
(b) Contracts through December 2013 for power as of June 30, 2011.
(c) Contracts through December 2013, December 2012, and May 2015 for heating oil, natural gas, and power, respectively, as of June 30, 2011.
(d) Contracts through December 2013, October 2016, May 2032 and December 2013 for heating oil, natural gas, power, and uranium, respectively, as of June 30, 2011.
(e) Not applicable.
(f) Includes AERG coal and heating oil, Marketing Company natural gas and power, and intercompany eliminations' for power.
Derivative Instruments Carrying Value 
                                     
      Balance Sheet Location   

Ameren(a)

      Ameren Missouri     Ameren Illinois     Genco  

2011:

                                  

Derivative assets designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative assets    $ 5       $ -      $ (b )    $ -   
    

Other assets

      2         -        -        -   
    

Total assets

    $ 7       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative liabilities    $ 3       $ (b )    $ -      $ -   
    

Other deferred credits and liabilities

      4         -        -        -   
    

Total liabilities

    $ 7       $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

                                  

Commodity contracts:

                                       

Heating oil

    MTM derivative assets    $ 49       $ 29      $ (b )    $ 15   
    

Other assets

      23         14        -        7   

Natural gas

    MTM derivative assets      5         -        (b )      1   
    

Other current assets

      -         -        2        -   
    

Other assets

      1         -        -        -   

Power

    MTM derivative assets      100         29        (b )      4   
    

Other current assets

      -         -        1        -   
    

Other assets

      85         1        68        -   
    

Total assets

    $ 263       $ 73      $ 71      $ 27   

Derivative liabilities not designated as hedging instruments(c)

                                  

Commodity contracts:

                                       

Heating oil

    MTM derivative liabilities    $ 4       $ (b )    $ -      $ 1   
    

Other current liabilities

      -         2        -        -   

Natural gas

    MTM derivative liabilities      75         (b )      60        2   
    

Other current liabilities

      -         10        -        -   
    

Other deferred credits and liabilities

      63         10        53        -   

Power

    MTM derivative liabilities      52         (b )      4        2   
    

MTM derivative liabilities - affiliates

      -         (b )      173        1   
    

Other current liabilities

      -         3        -        -   
    

Other deferred credits and liabilities

      14         1        96        -   

Uranium

    MTM derivative liabilities      1         (b )      -        -   
    

Other current liabilities

      -         1        -        -   
    

Other deferred credits and liabilities

      1         1        -        -   
    

Total liabilities

    $ 210       $ 28      $ 386      $ 6   

2010:

                                       

Derivative assets designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative assets    $ 3       $ -      $ (b )    $ -   
     Other assets      2         -        -        -   
    

Total assets

    $ 5       $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                  

Commodity contracts:

                                       

Power

    MTM derivative liabilities    $ 1       $ (b )    $ -      $ -   
    

Total liabilities

    $                           1       $ -      $ -      $                          -   
      Balance Sheet Location   

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

  

Derivative assets not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Heating oil

    MTM derivative assets    $ 42      $ 24      $ (b )    $ 14   
     Other current assets      -        -        -        -   
     Other assets      22        13        -        7   

Natural gas

    MTM derivative assets      4        1        (b )      1   
     Other current assets      -        -        1        -   
     Other assets      1        -        1        -   

Power

    MTM derivative assets      78        8        (b )      11   
     Other current assets      -        -        2        -   
     Other assets      20        -        6        -   

Uranium

    MTM derivative assets      2        2        (b )      -   
     Other current assets      -        -        -        -   
     Total assets    $ 169      $ 48      $ 10      $ 33   

Derivative liabilities not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Heating oil

    MTM derivative liabilities    $ 12      $ (b )    $ -      $ 4   
     Other current liabilities      -        7        -        -   
     Other deferred credits and liabilities      1        -        -        -   

Natural gas

    MTM derivative liabilities      87        (b )      73        2   
     Other current liabilities      -        11        -        -   
     Other deferred credits and liabilities      84        13        70        -   

Power

    MTM derivative liabilities      61        (b )      9        3   
     MTM derivative liabilities - affiliates      (b )      (b )      172        5   
     Other current liabilities      -        6        -        -   
     Other deferred credits and liabilities      7        -        179        -   
     Total liabilities    $                        252      $ 37      $ 503      $                        14   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Balance sheet line item not applicable to registrant.
(c) Includes derivatives subject to regulatory deferral.
Cumulative Pretax Net Gains (Losses) on All Derivative Instruments Reported in the Statement of Financial Position 
                                         
     

Ameren(a)

    

Ameren Missouri

    

Ameren Illinois

    

Genco

    

Other(a)

  

2011:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 3      $ -      $ -      $ -      $ 3   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

                                         

Heating oil derivative contracts(e)

      35        35        -        -        -   

Natural gas derivative contracts(f)

      (131 )      (20 )      (111 )      -        -   

Power derivative contracts(g)

      91        26        (204 )      -        269   

Uranium derivative contracts(h)

      (2 )      (2 )      -        -        -   

2010:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 8      $ -      $ -      $ -      $ 8   

Interest rate derivative contracts(c)(d)

     (9 )      -        -        (9 )      -   

Cumulative gains (losses) deferred in regulatory liabilities or assets:

                                         

Heating oil derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (165 )      (24 )      (141 )      -        -   

Power derivative contracts(g)

      1        3        (352 )      -        350   

Uranium derivative contracts(h)

      2        2        -        -        -   

 

(a) Includes amounts for Marketing Company and intercompany eliminations.
(b) Represents net gains associated with power derivative contracts at Ameren. These contracts are a partial hedge of electricity price exposure through December 2013 as of June 30, 2011. Current gains of $3 million and $8 million were recorded at Ameren as of June 30, 2011, and December 31, 2010, respectively.
(c) Includes net gains associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity, and the gain in OCI is amortized over a 10-year period that began in June 2002. The carrying value at June 30, 2011, and December 31, 2010, was less than $1 million and less than $1 million, respectively. The balance of the gain will be amortized by June 2012.
(d) Includes net losses associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco's April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008. The carrying value at June 30, 2011, and December 31, 2010, was a loss of $9 million and $10 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e)

Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through December 2013 as of June 30, 2011. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.

(f) Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and Ameren Illinois, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $69 million, $9 million, and $60 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(g) Represents net gains 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 2012 at Ameren Missouri, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $29 million, $28 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $5 million, $2 million, and $177 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
(h) Represents net losses and gains on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of June 30, 2011. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.
Cash Collateral Held From Counterparties 
                                                                         
      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                                                                                 

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ -       $  -    

2010:

                                                                                 

Ameren(a)

    $ -       $ -       $ -       $ -       $ -       $ -       $ -       $ 1       $ 1    

 

(a) Represents amounts held by Marketing Company. As of June 30, 2011, and December 31, 2010, Ameren registrant subsidiaries held no cash collateral.
Potential Loss on Counterparty Exposures 
                                                                         
      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                                                                                 

AMO

    $ -       $ 10       $ 1       $ 3       $ 33       $ 7       $ -       $ -       $ 54   

AIC

      -         -         27         -         -         -         -         -         27   

Genco

      -         4         1         -         1         -         3         -         9   

Other(b)

      317         4         6         5         35         205         -         67         639   

Ameren

     317         18         35         8         69         212         3         67         729   

2010:

                                                                                 

AMO

    $ -       $ 8       $ -       $ 1       $ 2       $ 10       $ -       $ -       $ 21   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         1         1         1         1         -         5         -         9   

Other(b)

      404         1         8         7         56         513         2         71         1,062   

Ameren

     404         10         11         9         59         523         7         71         1,094   

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.
Derivative Instruments With Credit Risk-Related Contingent Features 
                         
     

Aggregate Fair Value of

Derivative Liabilities(a)

     

Cash

Collateral Posted

      Potential Aggregate Amount of  Additional
Collateral Required(b)		  

2011:

                           

Ameren Missouri

    $ 113       $ 5         $                         67   

Ameren Illinois

      207         91         103   

Genco

      49         5         26   

Other(c)

      121         13         59   

Ameren

     490         114         255   

2010:

                           

Ameren Missouri

    $ 105       $ 7         $                        93   

Ameren Illinois

      233         109         111   

Genco

      31         -         28   

Other(c)

      62         18         42   

Ameren

     431         134         274   

 

(a) Prior to consideration of master trading and netting agreements and including NPNS contract exposures.
(b) As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is after consideration of the effects of such agreements.
(c) Includes amounts for Marketing Company and Ameren (parent).
Cash Flow Hedges 
                                 
     

Gain (Loss)

Recognized in
OCI(a)

    

Location of (Gain) Loss

Reclassified from

OCI into Income(b)

   

(Gain) Loss

Reclassified from

OCI into Income(b)

    

Location of Gain (Loss)

Recognized in Income(c)

   

Gain (Loss)

Recognized

in Income(c)

  

                             Three Months

 

                          

2011:

                                   

Ameren:(d)

                                   

Power

    $ (3 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ 3   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

                                   

Ameren:(d)

                                   

Power

    $ (16 )    Operating Revenues - Electric    $ (10 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

                             Six Months

 

                          

2011:

                                   

Ameren:(d)

                                   

Power

    $ (7 )    Operating Revenues - Electric    $ 2      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2010:

                                   

Ameren:(d)

                                   

Power

    $ 10      Operating Revenues - Electric    $ (14 )    Operating Revenues - Electric    $ (13 ) 

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

 

(a) Effective portion of gain (loss).
(b) Effective portion of (gain) loss on settlements.
(c) Ineffective portion of gain (loss) and amount excluded from effectiveness testing.
(d) Includes amounts from Ameren registrant and nonregistrant subsidiaries.
(e) Represents interest rate swaps settled in prior periods. The cumulative gain and loss on the interest rate swaps is being amortized into income over a 10-year period.
(f) Less than $1 million.
Other Derivatives 
                                             
           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               Three Months          Six Months  
                  2011     2010           2011     2010  
Ameren(a)    Heating oil    Operating Expenses - Fuel    $ (9 )    $ (7 )         $ 10      $ (6 ) 
     Natural gas (generation)    Operating Expenses - Fuel      -        -             -        (1 ) 
     Power    Operating Revenues - Electric      (5 )      (11 )           (7 )      20   
         

Total

    $ (14 )    $ (18 )         $ 3      $ 13   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ -           $ (1 )    $ 1   
    

Power

    Operating Revenues - Electric      -        -             -        (1 ) 
          Total    $ -      $ -           $ (1 )    $ -   
Genco    Heating oil    Operating Expenses - Fuel    $ (8 )    $ (5 )         $ 7      $ (4 ) 
    

Natural gas (generation)

    Operating Expenses - Fuel      -        -             -        (1 ) 
    

Power

    Operating Revenues      (1 )      -             (1 )      1   
          Total    $ (9 )    $ (5 )         $ 6      $ (4 ) 

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Derivatives that Qualify for Regulatory Deferral 
                                         
            Gain (Loss) Recognized in Regulatory  Liabilities or Regulatory Assets  
          Three Months          Six Months  
            2011     2010           2011     2010  

Ameren(a)

    Heating oil    $ (13 )    $ (9 )         $ 16      $ (8 ) 
    

Natural gas

      3        25             34        (81 ) 
    

Power

      88        33             90        23   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 75      $ 48           $ 136      $ (68 ) 

Ameren Missouri            

    Heating oil    $ (13 )    $ (9 )         $ 16      $ (8 ) 
    

Natural gas

      1        4             4        (11 ) 
    

Power

      23        (9 )           23        7   
    

Uranium

      (3 )      (1 )           (4 )      (2 ) 
    

Total

    $ 8      $ (15 )         $ 39      $ (14 ) 

Ameren Illinois

    Natural gas    $ 2      $ 21           $ 30      $ (70 ) 
    

Power

      121        150             148        17   
    

Total

    $ 123      $ 171           $ 178      $ (53 ) 

 

(a) Includes amounts for intercompany eliminations.
Maximum Exposure If Counterparties Fail To Perform on Contracts 
                                                                         
      Affiliates(a)     

Coal

Producers

     

Commodity

Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

     

Oil and Gas

Companies

     

Retail

Companies

      Total  

2011:

                                                                                 

AMO

    $ -       $ 22       $ 2       $ 5       $ 39       $ 7       $ -       $ -       $ 75    

AIC

      -         -         29         -         2         -         -         -         31    

Genco

      -         12         1         1         3         -         4         -         21    

Other(b)

      333         7         7         10         47         217         1         68         690    

Ameren

     333         41         39         16         91         224         5         68         817    

2010:

                                                                                 

AMO

    $ -       $ 21       $ 1       $ 2       $ 5       $ 11       $ 1       $ -       $ 41    

AIC

      -         -         3         -         1         -         -         -         4    

Genco

      -         6         2         1         1         -         6         -         16    

Other(b)

      410         3         10         19         65         539         3         72         1,121    

Ameren

     410         30         16         22         72         550         10         72         1,182    

 

(a) Primarily comprised of Marketing Company's exposure to Ameren Illinois related to financial contracts. The exposure is not eliminated at the consolidated Ameren level as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.
 
Fair Value Measurements (Tables)
Schedule of Fair Value Hierarchy of Assets and Liabilities Measured at Fair Value on Recurring Basis 

The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of June 30, 2011:

 

          

Quoted Prices in

Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

          Total      

Assets:

              

Ameren(a)             

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 72       $ 72   
 

Natural gas

      3         -         3         6   
 

Power

      -         18         174         192   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AMO

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         43         43   
 

Power

      -         2         28         30   
 

Nuclear Decommissioning Trust Fund(c):

            
 

Cash and cash equivalents

      1         -         -         1   
 

Equity securities:

            
 

U.S. large capitalization

      234         -         -         234   
 

Debt securities:

            
 

Corporate bonds

      -         45         -         45   
 

Municipal bonds

      -         2         -         2   
 

U.S. treasury and agency securities

      -         59         -         59   
 

Asset-backed securities

      -         13         -         13   
   

Other

      -         1         -         1   

AIC

  

Derivative assets - commodity contracts(b):

            
 

Natural gas

      -         -         2         2   
   

Power

      -         -         69         69   

Genco

  

Derivative assets - commodity contracts(b):

            
 

Heating oil

      -         -         22         22   
 

Natural gas

      1         -         -         1   
   

Power

      -         -         4         4   

Liabilities:

              

Ameren(a)

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

    $ -       $ -       $ 4       $ 4   
 

Natural gas

      18         -         120         138   
 

Power

      -         16         57         73   
   

Uranium

      -         -         2         2   

AMO

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         2         2   
 

Natural gas

      9         -         11         20   
 

Power

      -         1         3         4   
   

Uranium

      -         -         2         2   

AIC

  

Derivative liabilities - commodity contracts(b):

            
 

Natural gas

      5         -         108         113   
   

Power

      -         -         273         273   

Genco

  

Derivative liabilities - commodity contracts(b):

            
 

Heating oil

      -         -         1         1   
 

Natural gas

      2         -         -         2   
   

Power

      -         -         3         3   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 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, 2010:

 

           

Quoted Prices in
Active Markets for

Identical Assets

or Liabilities

(Level 1)

     

Significant Other

Observable Inputs

(Level 2)

     

Significant Other

Unobservable

Inputs

(Level 3)

              Total           

Assets:

               

Ameren(a)

    Derivative assets - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 64       $ 64    
  

Natural gas

      3         -         2         5    
  

Power

      -         17         86         103    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AMO

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         37         37    
  

Natural gas

      -         -         1         1    
  

Power

      -         3         5         8    
  

Uranium

      -         -         2         2    
   Nuclear Decommissioning Trust Fund(c):            
  

Cash and cash equivalents

      1         -         -         1    
  

Equity securities:

            
  

U.S. large capitalization

      228         -         -         228    
  

Debt securities:

            
  

Corporate bonds

      -         40         -         40    
  

Municipal bonds

      -         2         -         2    
  

U.S. treasury and agency securities

      -         50         -         50    
  

Asset-backed securities

      -         14         -         14    
    

Other

      -         1         -         1    

AIC

    Derivative assets - commodity contracts(b):            
  

Natural gas

      -         -         2         2    
    

Power

      -         -         8         8    

Genco

    Derivative assets - commodity contracts(b):            
  

Heating oil

      -         -         21         21    
  

Natural gas

      1         -         -         1    
    

Power

      -         -         11         11    

Liabilities:

               

Ameren(a)

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

    $ -       $ -       $ 13       $ 13    
  

Natural gas

      21         -         150         171    
    

Power

      -         19         50         69    

AMO

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         7         7    
  

Natural gas

      9         -         15         24    
    

Power

      -         3         3         6    

AIC

    Derivative liabilities - commodity contracts(b):            
  

Natural gas

      7         -         136         143    
    

Power

      -         -         360         360    

Genco

    Derivative liabilities - commodity contracts(b):            
  

Heating oil

      -         -         4         4    
  

Natural gas

      2         -         -         2    
    

Power

      -         -         8         8    

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The derivative asset and liability balances are presented net of counterparty credit considerations.
(c) Balance excludes $1 million of receivables, payables, and accrued income, net.
Schedule of Changes in the Fair Value of Financial Assets and Liabilities Classified as Level 3 in the Fair Value Hierarchy 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2011:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2011

      $ 96         $ 57         $         (a )       $ 29         $ 10   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (5 )         -           (a )         (3 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (14 )         (9 )         (a )         (3 )         (2 ) 

Purchases

        1           1           (a )         -           -   

Settlements

        (15 )         (8 )         (a )         (5 )         (2 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (14 )       $ (8 )       $ (a )       $ (4 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2011

      $ (120 )       $ (12 )       $ (108 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (20 )         (1 )         (19 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (20 )         (1 )         (19 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        22           2           20           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (18 )       $ (1 )       $ (17 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2011

      $ 31         $ 2         $ (325 )       $ 3         $ 351   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (15 )         -           -           (1 )         (14 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        66           (1 )         77           (a )         (10 ) 

Total realized and unrealized gains (losses)

        56           (1 )         77           (1 )         (19 ) 

Purchases

        50           29           -           -           21   

Sales

        (7 )         -           -           -           (7 ) 

Settlements

        (16 )         (6 )         44           (1 )         (53 ) 

Transfers into Level 3

        1           -           -           -           1   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ (1 )       $ 68         $ (1 )       $ (7 ) 

Uranium:

                         

Beginning balance at April 1, 2011

      $ 1         $ 1         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (3 )         (3 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (3 )         (3 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended June 30, 2010:

 

        Net derivative commodity contracts  
Three Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at April 1, 2010

      $ 54         $ 31         $         (a )       $ 18         $ 5   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (8 )         -           (a )         (6 )         (2 ) 

Included in regulatory assets/liabilities

        (9 )         (9 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (17 )         (9 )         (a )         (6 )         (2 ) 

Purchases

        33           17           (a )         11           5   

Settlements

        (41 )         (23 )         (a )         (13 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (16 )       $ (9 )       $ (a )       $ (5 )       $ (2 ) 

Natural gas:

                         

Beginning balance at April 1, 2010

      $ (162 )       $ (18 )       $ (144 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (6 )         (1 )         (5 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (6 )         (1 )         (5 )         -           -   

Purchases

        -           -           -           -           -   

Settlements

        30           4           26           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (6 )       $ (1 )       $ (5 )       $ -         $ -   

Power:

                         

Beginning balance at April 1, 2010

      $ 37         $ 5         $ (554 )       $ 3         $ 583   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       6           -           -           -           6   

Included in OCI

        (18 )         -           -           -           (18 ) 

Included in regulatory assets/liabilities

        29           1           98           (a )         (70 ) 

Total realized and unrealized gains (losses)

        17           1           98           -           (82 ) 

Purchases

        25           5           17           (2 )         5   

Sales

        2           -           -           3           (1 ) 

Settlements

        (19 )         (6 )         33           (1 )         (45 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (7 )         -           -           -           (7 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (5 )       $ (3 )       $ 67         $ -         $ (69 ) 

Uranium:

                         

Beginning balance at April 1, 2010

      $ (3 )       $ (3 )       $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (1 )         (1 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (1 )         (1 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ -         $ -         $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2011:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2011

      $ 51         $ 30         $         (a )       $ 17         $ 4   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        17           -           (a )         12           5   

Included in regulatory assets/liabilities

        22           22           (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        39           22           (a )         12           5   

Purchases

        2           2           (a )         -           -   

Settlements

        (24 )         (13 )         (a )         (8 )         (3 ) 

Ending balance at June 30, 2011

      $ 68         $ 41         $ (a )       $ 21         $ 6   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 30         $ 18         $ (a )       $ 9         $ 3   

Natural gas:

                         

Beginning balance at January 1, 2011

      $ (148 )       $ (14 )       $ (134 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (13 )         (1 )         (12 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (13 )         (1 )         (12 )         -           -   

Purchases

        1           -           1           -           -   

Settlements

        43           4           39           -           -   

Ending balance at June 30, 2011

      $ (117 )       $ (11 )       $ (106 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 9         $ 1         $ 8         $ -         $ -   

Power:

                         

Beginning balance at January 1, 2011

      $ 36         $ 2         $ (352 )       $ 3         $ 383   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       (18 )         -           -           (1 )         (17 ) 

Included in OCI

        5           -           -           -           5   

Included in regulatory assets/liabilities

        64           6           47           (a )         11   

Total realized and unrealized gains (losses)

        51           6           47           (1 )         (1 ) 

Purchases

        59           29           -           -           30   

Sales

        (16 )         -           -           -           (16 ) 

Settlements

        (16 )         (12 )         101           (1 )         (104 ) 

Transfers into Level 3

        1           (1 )         -           -           2   

Transfers out of Level 3

        2           1           -           -           1   

Ending balance at June 30, 2011

      $ 117         $ 25         $ (204 )       $ 1         $ 295   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ 59         $ -         $ 64         $ (1 )       $ (4 ) 

Uranium:

                         

Beginning balance at January 1, 2011

      $ 2         $ 2         $         (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (4 )         (4 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (4 )         (4 )         (a )         (a )         (a ) 

Ending balance at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2011

      $ (2 )       $ (2 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.

 

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the six months ended June 30, 2010:

 

        Net derivative commodity contracts  
Six Months      Ameren       

Ameren
Missouri

       

Ameren
Illinois

        Genco        Other(c)  

Heating oil:

                         

Beginning balance at January 1, 2010

      $ 60         $ 32         $         (a )       $ 21         $ 7   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        (10 )         -           (a )         (8 )         (2 ) 

Included in regulatory assets/liabilities

        (11 )         (11 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (21 )         (11 )         (a )         (8 )         (2 ) 

Purchases

        32           18           (a )         11           3   

Settlements

        (42 )         (23 )         (a )         (14 )         (5 ) 

Ending balance at June 30, 2010

      $ 29         $ 16         $ (a )       $ 10         $ 3   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (18 )       $ (10 )       $ (a )       $ (6 )       $ (2 ) 

Natural gas:

                         

Beginning balance at January 1, 2010

      $ (67 )       $ (6 )       $ (61 )       $ -         $ -   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

        -           -           -           -           -   

Included in regulatory assets/liabilities

        (109 )         (14 )         (95 )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (109 )         (14 )         (95 )         -           -   

Purchases

        (4 )         -           (4 )         -           -   

Settlements

        42           5           37           -           -   

Ending balance at June 30, 2010

      $ (138 )       $ (15 )       $ (123 )       $ -         $ -   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (81 )       $ (10 )       $ (71 )       $ -         $ -   

Power:

                         

Beginning balance at January 1, 2010

      $ 38         $ (1 )       $ (422 )       $ 1         $ 460   

Realized and unrealized gains (losses):

                         

Included in earnings(b)

       24           -           -           2           22   

Included in OCI

        6           -           -           -           6   

Included in regulatory assets/liabilities

        7           13           (69 )         (a )         63   

Total realized and unrealized gains (losses)

        37           13           (69 )         2           91   

Purchases

        38           4           17           (4 )         21   

Sales

        (5 )         1           -           5           (11 ) 

Settlements

        (29 )         (9 )         68           (1 )         (87 ) 

Transfers into Level 3

        (1 )         -           -           -           (1 ) 

Transfers out of Level 3

        (24 )         (3 )         -           -           (21 ) 

Ending balance at June 30, 2010

      $ 54         $ 5         $ (406 )       $ 3         $ 452   

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (7 )       $ 1         $ (79 )       $ 1         $ 70   

Uranium:

                         

Beginning balance at January 1, 2010

      $ (2 )       $ (2 )       $ (a )       $         (a )       $ (a ) 

Realized and unrealized gains (losses):

                         

Included in regulatory assets/liabilities

        (2 )         (2 )         (a )         (a )         (a ) 

Total realized and unrealized gains (losses)

        (2 )         (2 )         (a )         (a )         (a ) 

Ending balance at June 30, 2010

      $ (4 )       $ (4 )       $ (a )       $ (a )       $ (a ) 

Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2010

      $ (1 )       $ (1 )       $ (a )       $ (a )       $ (a ) 

 

(a) Not applicable.
(b) Net gains and losses on heating oil and natural gas derivative commodity contracts are recorded in Operating Expenses - Fuel, while net gains and losses on power derivative commodity contracts are recorded in Operating Revenues - Electric.
(c) Includes amounts for Merchant Generation nonregistrant subsidiaries and intercompany eliminations.
Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt and Capital Lease Obligations and Preferred Stock 
      June 30, 2011      December 31, 2010  
     

Carrying

Amount

     

Fair

Value

     

Carrying

Amount

     

Fair

Value

  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,859       $    7,666       $ 7,008       $    7,661   

Preferred stock

      142         102         142         102   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,954       $ 4,378       $ 3,954       $ 4,281   

Preferred stock

      80         61         80         62   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,956       $ 1,807       $ 2,067   

Preferred stock

      62         41         62         40   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 843       $ 824       $ 826   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Preferred stock not subject to mandatory redemption of the Ameren subsidiaries along with the 20% noncontrolling interest of EEI is recorded in Noncontrolling Interests on the balance sheet.
Commitments and Contingencies (Tables)
6 Months Ended
Jun. 30, 2011
Callaway Energy Center
Text Block 
Schedule of Estimated Capital Costs to Comply with Existing and Known Emissions Related Regulations
Text Block 
Schedule of Estimated Obligations for Manufactured Gas Plant Remediation
Text Block 
Schedule of Asbestos-Related Litigation Pending Lawsuits
Text Block 
Coal [Member]
 
Schedule of Estimated Purchased Power Commitments
Text Block 
Purchase Power [Member]
 
Schedule of Estimated Purchased Power Commitments
Text Block 
Callaway Energy Center 
Type and Source of Coverage    Maximum Coverages     Maximum Assessments
for Single Incidents		  

Public liability and nuclear worker liability:

     

American Nuclear Insurers

    $ 375      $ -   

Pool participation

      12,219 (a)      118 (b) 
   $ 12,594 (c)    $ 118   

Property damage:

     

Nuclear Electric Insurance Ltd.

    $ 2,750 (d)    $ 23   

Replacement power:

     

Nuclear Electric Insurance Ltd.

    $ 490 (e)    $ 9   

Energy Risk Assurance Company

    $ 64 (f)    $ -   

 

(a) Provided through mandatory participation in an industry-wide retrospective premium assessment program.
(b) Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year.
(c) Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.
(d) Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.
(e) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million.
(f) Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction.
Schedule of Estimated Capital Costs to Comply with Existing and Known Emissions Related Regulations 
      2011      2012 - 2015      2016 - 2020      Total  

AMO(a)

    $ 40       $ 315     

-

    $ 390       $ 905     

-

    $ 1,105       $ 1,260     

-

    $ 1,535   

Genco

          125         355     

-

      435         60     

-

      75         540     

-

      635   

AERG

      10         170     

-

      210         10     

-

      15         190     

-

      235   

Ameren

    $ 175       $     840     

-

    $     1,035       $     975     

-

    $   1,195       $   1,990     

-

    $   2,405   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.
Schedule of Estimated Obligations for Manufactured Gas Plant Remediation 
      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   121       $   199       $ 121   

Ameren Missouri

      3         4         3   

Ameren Illinois

      118         195         118   

 

(a) Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate.
Schedule of Asbestos-Related Litigation Pending Lawsuits 
Ameren    AMO    AIC    Genco   Total(a)

5

    54    74    (b)   95

 

(a) Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
(b) As of June 30, 2011, eight asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.
Schedule of Estimated Purchased Power Commitments 
      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     669       $     1,153       $     801       $     643       $     634       $     1,651   

Ameren Missouri

      244         618         609         630         620         1,589   
Schedule of Estimated Purchased Power Commitments 
      2011      2012      2013      2014      2015      Thereafter  

Ameren

    $     178       $     200       $       314       $     129       $     55       $     826   

Ameren Illinois

      165         177         290         106         32         624   
Other Comprehensive Income (Tables)
Schedule of Comprehensive Income
      Three Months     Six Months  
      2011     2010     2011     2010  

Ameren:(a)

         

Net income

    $ 139      $ 155      $   213      $   261   

Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit) of $(5), $(7), $(4), and $11, respectively

      (8 )      (11 )      (6 )      17   

Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(4), $3, $(2), and $12, respectively

      7        (5 )      3        (20 ) 

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $5, $(2), and $6, respectively

      -        7        (1 )      6   

Total comprehensive income, net of taxes

    $ 138      $ 146      $ 209      $ 264   

Less: Net income attributable to noncontrolling interests, net of taxes

      1        3        4        7   

Total comprehensive income attributable to Ameren Corporation, net of taxes

    $ 137      $ 143      $ 205      $ 257   

Ameren Illinois:

         

Net income

    $ 38      $ 57      $ 72      $ 105   

Pension and other postretirement activity, net of income taxes (benefit) of $(1), $- , $(1), and $- , respectively

      (1 )      -        (2 )      (1 ) 

Total comprehensive income, net of taxes

    $ 37      $ 57      $ 70      $ 104   

Genco:

         

Net income

    $ 13      $ 14      $ 35      $ 38   

Pension and other postretirement activity, net of income taxes (benefit) of $1, $3 , $1, and $5 , respectively

      -        5        1        4   

Total comprehensive income, net of taxes

    $ 13      $ 19      $ 36      $ 42   

Less: Net income attributable to noncontrolling interest, net of taxes

      -        1        1        2   

Total comprehensive income attributable to Genco

    $ 13      $ 18      $ 35      $ 40   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
Retirement Benefits (Tables)
Schedule of Defined Benefit Plans Disclosures 
      Pension Benefits(a)     Postretirement Benefits(a)  
     Three Months     Six Months     Three Months     Six Months  
      2011     2010     2011     2010     2011     2010     2011     2010  

Service cost

    $ 18      $ 16      $ 38      $ 33      $ 5      $ 5      $ 11      $ 10   

Interest cost

      45        46        90        93        14        14        29        30   

Expected return on plan assets

      (54 )      (53 )      (108 )      (106 )      (13 )      (14 )      (27 )      (28 ) 

Amortization of:

                 

Transition obligation

      -        -        -        -        1        1        1        1   

Prior service cost (benefit)

     (1 )      2        (1 )      4        (2 )      (2 )      (4 )      (4 ) 

Actuarial loss (gain)

     10        4        21        9        1        (1 )      2        1   

Net periodic cost

    $ 18      $ 15      $ 40      $ 33      $ 6      $ 3      $ 12      $ 10   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Schedule Net Periodic Benefit Cost for Pension and Postretirement Benefit Plans by Company 
      Pension Costs      Postretirement Costs  
     Three Months      Six Months      Three Months      Six Months  
      2011      2010      2011      2010      2011      2010      2011      2010  

Ameren Missouri

    $ 12       $ 9       $ 26       $ 21       $ 2       $ 2       $ 5       $ 5   

Ameren Illinois

      3         4         8         6         4         1         6         4   

Genco

      3         2         5         5         -         -         1         1   

Other

      -         -         1         1         -         -         -         -   

Ameren(a)

    $ 18       $ 15       $ 40       $ 33       $ 6       $ 3       $ 12       $ 10   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Segment Information (Tables)
Schedule of Segment Reporting Information, by Segment
                                                 
Three Months    Ameren
Missouri		      Ameren
Illinois		      Merchant
Generation		     Other     Intersegment
Eliminations		     Consolidated  

2011:

                                                   

External revenues

    $ 814       $ 619       $ 347      $ 1      $ -      $ 1,781   

Intersegment revenues

      8         4         49        -        (61 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      90         37         15        (4 )      -        138   

2010:

                                                   

External revenues

    $ 756       $ 644       $ 325      $ -      $ -      $ 1,725   

Intersegment revenues

      5         3         60        3        (71 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      113         46         (2 )      (5 )      -        152   
Six Months                                             

2011:

                                                   

External revenues

    $ 1,581       $ 1,424       $ 679      $ 1      $ -      $ 3,685   

Intersegment revenues

      13         7         96        1        (117 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      111         70         35        (7 )      -        209   

2010:

                                                   

External revenues

    $ 1,433       $ 1,553       $ 679      $ -      $ -      $ 3,665   

Intersegment revenues

      10         5         134        6        (155 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      140         81         42        (9 )      -        254   
Six Months    Ameren
Missouri		      Ameren
Illinois		      Merchant
Generation		     Other     Intersegment
Eliminations		     Consolidated  

As of June 30, 2011:

                                                   

Total assets

    $ 12,527       $ 7,154       $ 3,861      $  1,324      $ (1,475 )    $ 23,391   

As of December 31, 2010:

                                                   

Total assets

    $ 12,504       $ 7,406       $ 3,934      $ 1,354      $ (1,683 )    $ 23,515   

 

(a) Represents net income (loss) available to common stockholders.
Summary of Significant Accounting Policies (Narrative) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Dec. 31, 2010
3 Months Ended
Jun. 30, 2011
Merchant Generation [Member]
6 Months Ended
Jun. 30, 2011
Ameren Missouri [Member]
1 Months Ended
Jun. 30, 2011
Ameren Energy Generating Company [Member]
3 Months Ended
Jun. 30, 2011
Ameren Energy Generating Company [Member]
Dec. 31, 2010
Ameren Energy Generating Company [Member]
Jun. 30, 2011
Renewable Energy Credits [Member]
1 Months Ended
Jan. 31, 2011
Performance Share Units [Member]
Fair value of share unit
 
 
 
 
 
 
 
 
 
 
 
$ 31.41 
Closing common share price
 
 
 
 
$ 28.19 
 
 
 
 
 
 
 
Three-year risk-free rate
 
 
1.08% 
 
 
 
 
 
 
 
 
 
Volatility rate, minimum
 
 
22.00% 
 
 
 
 
 
 
 
 
 
Volatility rate, maximum
 
 
36.00% 
 
 
 
 
 
 
 
 
 
Share-based compensation expense
$ 4 
$ 2 
$ 7 
$ 7 
 
 
 
 
 
 
 
 
Employee service share-based compensation, tax benefit from compensation expense
2 
1 
3 
3 
 
 
 
 
 
 
 
 
Unrecognized share-based compensation expense
27 
 
27 
 
 
 
 
 
 
 
 
 
Unrecognized compensation costs on nonvested awards, weighted average period of recognition, in months
 
 
22 
 
 
 
 
 
 
 
 
 
Pretax impairment charge
 
 
 
 
 
2 
1 
 
1 
 
 
 
Book value
4 
 
4 
 
7 
 
 
 
 
3 
3 
 
Unrecognized tax benefits
198 
 
198 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefits that would impact effective tax rate
2 
 
2 
 
 
 
 
 
 
 
 
 
Percentage of EEI not owned by Ameren
20.00% 
 
20.00% 
 
 
 
 
 
 
 
 
 
Proceeds from sale of machinery and equipment
 
 
 
 
 
 
 
45 
 
 
 
 
Pretax gain recognized on sale of machinery and equipment
 
 
 
 
 
 
 
$ 8 
 
 
 
 
Summary of Significant Accounting Policies (Long-Term Incentive Plan) (Details) (USD $)
6 Months Ended
Jun. 30, 2011
Restricted Shares [Member]
 
Nonvested at January 1, 2011
83,154 1
Dividends
518 1
Forfeitures
(560)1
Vested
(63,574)1 2
Nonvested at June 30, 2011
19,538 1
Nonvested at January 1, 2011
$ 49.87 1
Dividends
28.48 1
Forfeitures
$ 50.45 1
Vested
$ 49.47 1 2
Nonvested at June 30, 2011
$ 51.21 1
Performance Share Units [Member]
 
Nonvested at January 1, 2011
1,142,768 3
Granted
731,962 3 4
Forfeitures
(10,261)3
Vested
(131,343)2 3
Nonvested at June 30, 2011
1,733,126 3
Nonvested at January 1, 2011
$ 23.96 3
Granted
$ 31.41 3 4
Forfeitures
$ 26.14 3
Vested
$ 30.67 2 3
Nonvested at June 30, 2011
$ 26.58 3
Summary of Significant Accounting Policies (Schedule of Amortization Expense For Intangible Assets) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Summary of Significant Accounting Policies
 
 
 
 
Amortization expense based on usage of emission allowances
$ 1 1
$ 7 1
$ 2 1
$ 10 1
Summary of Significant Accounting Policies (Schedule of Excise Taxes) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Summary of Significant Accounting Policies
 
 
 
 
Excise tax expense
$ 44 
$ 44 
$ 95 
$ 90 
Summary of Significant Accounting Policies (Schedule of Noncontrolling Interest) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Summary of Significant Accounting Policies
 
 
 
 
Noncontrolling interest, beginning of period
$ 155 
$ 206 
$ 154 
$ 204 
Net income attributable to noncontrolling interest
1 1
3 1
4 1
7 1
Dividends paid to noncontrolling interest holders
(1)
(3)
(3)
(5)
Noncontrolling interest, end of period
$ 155 
$ 206 
$ 155 
$ 206 
Rate and Regulatory Matters (Narrative) (Details) (USD $)
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,		 3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,		 1 Months Ended
Jul. 31,		 1 Months Ended
Jun. 30,
2011
2010
2011
2010
Sep. 30, 2011
Dec. 31, 2010
0 Months Ended
Jul. 13, 2011
Ameren Missouri [Member]
Final Rate Order [Member]
Electric Distribution [Member]
May 31, 2010
Ameren Missouri [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Jan. 31, 2009
Ameren Missouri [Member]
Final Rate Order [Member]
Electric Distribution [Member]
6 Months Ended
Jun. 30, 2011
Ameren Missouri [Member]
FAC Prudence Review [Member]
months
2011
Ameren Illinois [Member]
2010
Ameren Illinois [Member]
2011
Ameren Illinois [Member]
2010
Ameren Illinois [Member]
Dec. 31, 2010
Ameren Illinois [Member]
1 Months Ended
Jul. 31, 2011
Ameren Illinois [Member]
Original Rate Order [Member]
Gas Distribution [Member]
1 Months Ended
Feb. 28, 2011
Ameren Illinois [Member]
Original Rate Order [Member]
Electric Distribution [Member]
2011
Ameren Illinois [Member]
Pending Rate Order [Member]
Gas Distribution [Member]
2011
Ameren Illinois [Member]
Pending Rate Order [Member]
Electric Distribution [Member]
Jun. 30, 2011
Callaway Unit 2 [Member]
2011
Pending Rate Order [Member]
ICC Staff Position [Member]
Gas Distribution [Member]
2011
Pending Rate Order [Member]
ICC Staff Position [Member]
Electric Distribution [Member]
Authorized increase in revenue from utility service
 
 
 
 
 
 
$ 173,000,000 
$ 230,000,000 
$ 162,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount held by circuit court based on appeal of electric rate order
 
 
 
 
 
 
 
8,000,000 
16,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of industrial customers who received a stay from circuit court
 
 
 
 
 
 
 
4 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase in normalized net fuel costs
 
 
 
 
 
 
52,000,000 
119,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility revenue increase requested
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
50,000,000 
40,000,000 
 
16,000,000 
(10,000,000)
Rate of return on common equity
 
 
 
 
 
 
10.20% 
 
 
 
 
 
 
 
 
10.75% 
11.00% 
 
 
 
8.90% 
9.72% 
Percent of capital structure composed of equity
 
 
 
 
 
 
52.20% 
 
 
 
 
 
 
 
 
52.90% 
52.90% 
 
 
 
51.80% 
51.80% 
Rate base
 
 
 
 
 
 
6,600,000,000 
 
 
 
 
 
 
 
 
957,000,000 
2,000,000,000 
 
 
 
942,000,000 
2,000,000,000 
Recovery and refund period
 
 
12 months to 8 months 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sharing level for FAC
 
 
 
 
 
 
95.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Request to defer fixed costs not recovered from Noranda, amount
 
 
 
 
 
 
 
 
 
36,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Time required to complete FAC prudence reviews, in months
 
 
 
 
 
 
 
 
 
18 
 
 
 
 
 
 
 
 
 
 
 
 
Impairment of regulatory asset
 
 
 
 
 
 
 
 
 
18,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Interest charges
104,000,000 
115,000,000 
223,000,000 
247,000,000 
 
 
 
 
 
1,000,000 
35,000,000 
34,000,000 1
70,000,000 
71,000,000 1
 
 
 
 
 
 
 
 
Pretax earnings recognized associated with sales contracts
184,000,000 
 
184,000,000 
 
 
267,000,000 
 
 
 
25,000,000 
243,000,000 
 
243,000,000 
 
260,000,000 
 
 
 
 
 
 
 
Capitalized costs relating to construction of new nuclear unit
17,945,000,000 
 
17,945,000,000 
 
 
17,853,000,000 
 
 
 
 
4,657,000,000 
 
4,657,000,000 
 
4,576,000,000 
 
 
 
 
67,000,000 
 
 
Disallowed capitalized costs associated with rebuilt Taum Sauk energy center
 
 
 
 
$ 89,000,000 
 
$ 89,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate and Regulatory Matters (Schedule of Regulatory Assets and Liabilities) (Details) (USD $)
In Millions
Jun. 30, 2011
Dec. 31, 2010
Regulatory assets
$ 1,224 
$ 1,263 
Regulatory liabilities
1,424 
1,319 
Ameren Missouri [Member] |
Demand Side Costs [Member]
 
 
Regulatory assets
33 1
 
Ameren Missouri [Member] |
Construction Accounting For Pollution Control Equipment [Member]
 
 
Regulatory assets
25 1
 
Ameren Missouri [Member] |
SO2 Emissions Allowances Sales Tracker [Member]
 
 
Regulatory assets
8 2
 
Ameren Missouri [Member] |
FERC-Ordered MISO Resettlements [Member]
 
 
Regulatory assets
2 2
 
Ameren Missouri [Member] |
2006 Storm Costs [Member]
 
 
Regulatory assets
1 2
 
Ameren Missouri [Member] |
Vegetation Management And Infrastructure Inspection [Member]
 
 
Regulatory liabilities
3 2
 
Ameren Missouri [Member] |
Pension And Postretirement Benefit Cost Tracker For 2010 Costs [Member]
 
 
Regulatory liabilities
11 1
 
Ameren Missouri [Member]
 
 
Regulatory assets
$ 55 
 
Credit Facility Borrowings and Liquidity (Narrative) (Details) (USD $)
6 Months Ended
Jun. 30, 2011
Commercial Paper [Member]
Jun. 30, 2011
2010 Credit Agreements [Member]
Jun. 30, 2011
2010 Credit Agreements [Member]
2010 Ameren Credit Agreement [Member]
Jun. 30, 2011
Ameren Revolving Credit Facility [Member]
Jun. 2, 2010
Ameren Revolving Credit Facility [Member]
6 Months Ended
Jun. 30, 2011
2010 Ameren Credit Agreement [Member]
Letters of credit, outstanding amount
 
$ 15,000,000 
 
 
 
 
Available amounts under the facilities
 
 
1,600,000,000 
 
 
 
Line of credit facility, maximum borrowing capacity
500,000,000 
 
 
 
20,000,000 
 
Commercial paper outstanding
317,000,000 
 
 
 
 
 
Average daily commercial paper borrowings outstanding
338,000,000 
 
 
 
 
 
Debt instrument, interest rate, effective percentage
0.87% 
 
 
 
2.25% 
 
Peak short term borrowings
$ 400,000,000 
 
 
 
 
 
Peak short term borrowings interest rate
1.46% 
 
 
 
 
 
Maximum consolidated indebtedness as a percent of total capitalization
 
 
65.00% 
65.00% 
 
 
Actual debt-to-capital ratio
 
 
49 
49 
 
 
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
 
 
 
2.0 
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date
 
 
 
 
 
5.0 
Credit Facility Borrowings and Liquidity (Borrowing Activity on Credit Agreements) (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Jun. 30, 2011
Peak credit facility borrowings during 2011
$ 440 
2010 Missouri Credit Agreement [Member]
 
Average daily borrowings outstanding during 2011
181 
Outstanding credit facility borrowings at period end
200 
Weighted-average interest rate during 2011
2.31% 
Peak credit facility borrowings during 2011
340 1
Peak interest rate during 2011
4.30% 
Genco Credit Agreement 2010 [Member]
 
Average daily borrowings outstanding during 2011
83 
Outstanding credit facility borrowings at period end
 
Weighted-average interest rate during 2011
2.30% 
Peak credit facility borrowings during 2011
$ 100 1
Peak interest rate during 2011
2.31% 
Long-Term Debt and Equity Financings (Details) (USD $)
In Millions, unless otherwise specified
6 Months Ended
Jun. 30,
3 Months Ended
Jun. 30, 2011
2011
2010
1 Months Ended
Jun. 30, 2011
Ameren Illinois [Member]
6 Months Ended
Jun. 30, 2011
Senior Unsecured Notes 8.875% Due 2014 [Member]
Common stock, shares issued
0.6 
1.2 
 
 
 
Common stock, value of shares issued
$ 15 
$ 32 
$ 43 
 
 
Amount of senior notes matured and retired
 
 
 
$ 150 
 
Interest rate on senior unsecured notes
 
 
 
6.625% 
 
Excess in indebtedness upon default of maturity
 
 
 
 
25 
Other Income and Expenses (Other Income and Expenses) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Miscellaneous income:
 
 
 
 
Allowance for equity funds used during construction
$ 9 1
$ 13 1
$ 15 1
$ 26 1
Interest income on industrial development revenue bonds
7 1
7 1
14 1
14 1
Interest and dividend income
1 1
1 1
2 1
2 1
Other
 
3 1
2 1
4 1
Total miscellaneous income
17 1
24 1
33 1
46 1
Miscellaneous expense:
 
 
 
 
Donations
1 1
1 1
3 1
3 1
Other
4 1
1 1
7 1
6 1
Total miscellaneous expense
$ 5 1
$ 2 1
$ 10 1
$ 9 1
Derivative Financial Instruments (Narrative) (Details) (USD $)
In Millions
Jun. 30, 2011
Dec. 31, 2010
Derivative Financial Instruments
 
 
Counterparty letters of credit held as collateral
$ 16 
$ 28 
Derivative Financial Instruments (Open Gross Derivative Volumes by Commodity Type) (Details)
Jun. 30, 2011
Dec. 31, 2010
Coal (in tons) [Member]
 
 
NPNS Contract
66,000,000 1
73,000,000 1
Heating Oil (in gallons) [Member]
 
 
Other Derivatives
40,000,000 2
55,000,000 2
Derivatives That Qualify for Regulatory Deferral
62,000,000 3
80,000,000 3
Natural Gas (in mmbtu) [Member]
 
 
NPNS Contract
72,000,000 1
98,000,000 1
Other Derivatives
26,000,000 2
21,000,000 2
Derivatives That Qualify for Regulatory Deferral
196,000,000 3
194,000,000 3
Power (in Megawatt Hours) [Member]
 
 
NPNS Contract
79,000,000 1
63,000,000 1
Cash Flow Hedges
21,000,000 4
2,000,000 4
Other Derivatives
54,000,000 2
61,000,000 2
Derivatives That Qualify for Regulatory Deferral
20,000,000 3
18,000,000 3
Uranium (in pounds) [Member]
 
 
NPNS Contract
5,710,000 1
5,810,000 1
Derivatives That Qualify for Regulatory Deferral
458,000 3
185,000 3
Derivative Financial Instruments (Derivative Instruments Carrying Value) (Details) (USD $)
In Millions
Jun. 30, 2011
Dec. 31, 2010
Designated as Hedging Instrument [Member]
 
 
Derivative assets hedging instruments
$ 7 
$ 5 
Derivative liabilities as hedging instruments
7 
1 
Designated as Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative assets hedging instruments
5 
3 
Designated as Hedging Instrument [Member] |
Power [Member] |
Other Assets [Member]
 
 
Derivative assets hedging instruments
2 
2 
Designated as Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
3 
1 
Designated as Hedging Instrument [Member] |
Power [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
4 
 
Not Designated as Hedging Instrument [Member]
 
 
Derivative assets hedging instruments
263 1
169 1
Derivative liabilities as hedging instruments
210 1
252 1
Not Designated as Hedging Instrument [Member] |
Heating Oil [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative assets hedging instruments
49 1
42 1
Not Designated as Hedging Instrument [Member] |
Heating Oil [Member] |
Other Assets [Member]
 
 
Derivative assets hedging instruments
23 1
22 1
Not Designated as Hedging Instrument [Member] |
Heating Oil [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
4 1
12 1
Not Designated as Hedging Instrument [Member] |
Heating Oil [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
 
1 1
Not Designated as Hedging Instrument [Member] |
Natural Gas [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative assets hedging instruments
5 1
4 1
Not Designated as Hedging Instrument [Member] |
Natural Gas [Member] |
Other Assets [Member]
 
 
Derivative assets hedging instruments
1 1
1 1
Not Designated as Hedging Instrument [Member] |
Natural Gas [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
75 1
87 1
Not Designated as Hedging Instrument [Member] |
Natural Gas [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
63 1
84 1
Not Designated as Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative assets hedging instruments
100 1
78 1
Not Designated as Hedging Instrument [Member] |
Power [Member] |
Other Assets [Member]
 
 
Derivative assets hedging instruments
85 1
20 1
Not Designated as Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
52 1
61 1
Not Designated as Hedging Instrument [Member] |
Power [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
14 1
7 1
Not Designated as Hedging Instrument [Member] |
Uranium [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative assets hedging instruments
 
2 1
Not Designated as Hedging Instrument [Member] |
Uranium [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
1 1
 
Not Designated as Hedging Instrument [Member] |
Uranium [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative liabilities as hedging instruments
$ 1 1
 
Derivative Financial Instruments (Cumulative Amount of Pretax Net Gains (losses) on All Derivative Instruments) (Details) (USD $)
In Millions
6 Months Ended
Jun. 30, 2011
12 Months Ended
Dec. 31, 2010
Current losses deferred as regulatory assets
$ 184 
$ 267 
Current gains deferred as regulatory liabilities
160 
99 
Accumulated Other Comprehensive Income (Loss) [Member] |
Interest Rate Contract [Member]
 
 
Cumulative deferred pretax gains (losses)
(9)1 2 3
(9)1 2 3
Accumulated Other Comprehensive Income (Loss) [Member] |
Power [Member]
 
 
Cumulative deferred pretax gains (losses)
3 1 4
8 1 4
Regulatory Liabilities or Assets [Member] |
Heating Oil [Member]
 
 
Cumulative deferred pretax gains (losses)
35 1 5
19 1 5
Regulatory Liabilities or Assets [Member] |
Natural Gas [Member]
 
 
Cumulative deferred pretax gains (losses)
(131)1 6
(165)1 6
Regulatory Liabilities or Assets [Member] |
Power [Member]
 
 
Cumulative deferred pretax gains (losses)
91 1 7
1 1 7
Regulatory Liabilities or Assets [Member] |
Uranium [Member]
 
 
Cumulative deferred pretax gains (losses)
(2)1 8
2 1 8
Power [Member]
 
 
Gain (loss) to be amortized in next year
3.0 
8.0 
Current losses deferred as regulatory assets
5 
13 
Current gains deferred as regulatory liabilities
29 
8 
Heating Oil [Member]
 
 
Current losses deferred as regulatory assets
2 
6 
Current gains deferred as regulatory liabilities
24 
13 
Natural Gas [Member]
 
 
Current losses deferred as regulatory assets
69 
84 
Current gains deferred as regulatory liabilities
2 
1 
Uranium [Member]
 
 
Current losses deferred as regulatory assets
1 
 
Current gains deferred as regulatory liabilities
 
2 
Interest Rate Swap [Member]
 
 
Gain (loss) to be amortized in next year
1.4 
 
Carrying value of net gains associated with interest rate swaps
1 
1 
Carrying value of net losses associated with interest rate swaps
$ 9 
$ 10 
[5] Represents net gains on heating oil derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through December 2013 as of June 30, 2011. Current gains deferred as regulatory liabilities include $24 million and $24 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current losses deferred as regulatory assets include $2 million and $2 million at Ameren and Ameren Missouri as of June 30, 2011, respectively. Current gains deferred as regulatory liabilities include $13 million and $13 million at Ameren and Ameren Missouri as of December 31, 2010, respectively. Current losses deferred as regulatory assets include $6 million and $6 million at Ameren and Ameren Missouri as of December 31, 2010, respectively.
[6] Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2016 at Ameren, Ameren Missouri, and Ameren Illinois, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $69 million, $9 million, and $60 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $84 million, $11 million, and $73 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
[7] Represents net gains 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 2012 at Ameren Missouri, in each case as of June 30, 2011. Current gains deferred as regulatory liabilities include $29 million, $28 million, and $1 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current losses deferred as regulatory assets include $5 million, $2 million, and $177 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2011. Current gains deferred as regulatory liabilities include $8 million, $6 million, and $2 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010. Current losses deferred as regulatory assets include $13 million, $3 million, and $181 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2010.
Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform on Contracts) (Details) (USD $)
In Millions
6 Months Ended
Jun. 30, 2011
12 Months Ended
Dec. 31, 2010
Maximum exposure to counterparties related to derivative contracts
$ 817 
$ 1,182 
Affiliates [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
333 1
410 1
Coal Producers [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
41 
30 
Commodity Marketing Companies [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
39 
16 
Electric Utilities [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
16 
22 
Financial Companies [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
91 
72 
Municipalities/Cooperatives [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
224 
550 
Oil and Gas Companies [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
5 
10 
Retail Companies [Member]
 
 
Maximum exposure to counterparties related to derivative contracts
$ 68 
$ 72 
Derivative Financial Instruments (Cash Collateral Held from Counterparties) (Details) (USD $)
In Millions
Jun. 30, 2011
Dec. 31, 2010
Cash collateral held from counterparties
 1
$ 1 1
Affiliates [Member]
 
 
Cash collateral held from counterparties
 1
 1
Coal Producers [Member]
 
 
Cash collateral held from counterparties
 1
 1
Commodity Marketing Companies [Member]
 
 
Cash collateral held from counterparties
 1
 1
Electric Utilities [Member]
 
 
Cash collateral held from counterparties
 1
 1
Financial Companies [Member]
 
 
Cash collateral held from counterparties
 1
 1
Municipalities/Cooperatives [Member]
 
 
Cash collateral held from counterparties
 1
 1
Oil and Gas Companies [Member]
 
 
Cash collateral held from counterparties
 1
 1
Retail Companies [Member]
 
 
Cash collateral held from counterparties
 1
$ 1 1
Derivative Financial Instruments (Potential Loss on Counterparty Exposures) (Details) (USD $)
In Millions
Jun. 30, 2011
Dec. 31, 2010
Potential loss on counterparty exposures related to derivative contracts
$ 729 
$ 1,094 
Affiliates [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
317 1
404 1
Coal Producers [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
18 
10 
Commodity Marketing Companies [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
35 
11 
Electric Utilities [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
8 
9 
Financial Companies [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
69 
59 
Municipalities/Cooperatives [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
212 
523 
Oil and Gas Companies [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
3 
7 
Retail Companies [Member]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 67 
$ 71 
Derivative Financial Instruments (Cash Flow Hedges) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Power [Member]
 
 
 
 
Amount of Gain (Loss) Recognized in OCI
$ (3)1 2
$ (16)1 2
$ (7)1 2
$ 10 1 2
Operating Revenues-Electric [Member] |
Power [Member]
 
 
 
 
Amount of (Gain) Loss Reclassified from OCI into Income
1 2 3
(10)2 3
2 2 3
(14)2 3
Amount of Gain (Loss) Recognized in Income on Derivatives
3 2 4
(13)2 4
2 2 4
(13)2 4
Interest Rate Contract [Member]
 
 
 
 
Amount of Gain (Loss) Recognized in OCI
 1 2 5
 1 2 5
 1 2 5
 1 2 5
Interest Charges [Member] |
Interest Rate Contract [Member]
 
 
 
 
Amount of Gain (Loss) Recognized in Income on Derivatives
 
 2 4 5
 2 4 5
 2 4 5
Cash Flow Hedge Gain (Loss) Reclassified to Interest Expense, Net
$ 1 
 
$ 1 
 
Derivative Financial Instruments (Other Derivatives) (Details) (Not Designated as Hedging Instrument [Member], USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
$ (14)1
$ (18)1
$ 3 1
$ 13 1
Operating Revenues-Electric [Member] |
Power [Member]
 
 
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
(5)1
(11)1
(7)1
20 1
Heating Oil [Member] |
Operating Expenses-Fuel [Member]
 
 
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
(9)1
(7)1
10 1
(6)1
Natural Gas [Member] |
Operating Expenses-Fuel [Member]
 
 
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
 
 
 
$ (1)1
Derivative Financial Instruments (Derivatives that Qualify for Regulatory Deferral) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Amount Gain Loss On Derivative Instruments That Qualify For Regulatory Deferral Net
$ 75 1
$ 48 1
$ 136 1
$ (68)1
Heating Oil [Member]
 
 
 
 
Amount Gain Loss On Derivative Instruments That Qualify For Regulatory Deferral Net
(13)1
(9)1
16 1
(8)1
Natural Gas (Generation) [Member]
 
 
 
 
Amount Gain Loss On Derivative Instruments That Qualify For Regulatory Deferral Net
3 1
25 1
34 1
(81)1
Power [Member]
 
 
 
 
Amount Gain Loss On Derivative Instruments That Qualify For Regulatory Deferral Net
88 1
33 1
90 1
23 1
Uranium [Member]
 
 
 
 
Amount Gain Loss On Derivative Instruments That Qualify For Regulatory Deferral Net
$ (3)1
$ (1)1
$ (4)1
$ (2)1
Fair Value Measurements (Narrative) (Details) (USD $)
In Millions
6 Months Ended
Jun. 30,
2011
2010
12 Months Ended
Dec. 31, 2010
Fair Value Measurements
 
 
 
Loss recognized related to valuation adjustments for counterparty default risk
$ 1 
 
 
Gain recognized related to valuation adjustments for counter party default risk
 
1 
 
Valuation adjustments related to derivative contracts
$ 1 
 
$ 2 
Fair Value Measurements (Schedule of Fair Value Hierarchy of Assets and Liabilities Measured at Fair Value on Recurring Basis) (Details) (USD $)
In Millions
Jun. 30, 2011
Dec. 31, 2010
Excluded receivables, payables, and accrued income, net
$ 1 
$ 1 
Heating Oil [Member] |
Fair Value, Inputs, Level 3 [Member] |
Commodity Contract [Member]
 
 
Derivative assets
72 1 2
64 1 2
Derivative liabilities
4 1 2
13 1 2
Heating Oil [Member] |
Commodity Contract [Member]
 
 
Derivative assets
72 1 2
64 1 2
Derivative liabilities
4 1 2
13 1 2
Natural Gas [Member] |
Fair Value, Inputs, Level 1 [Member] |
Commodity Contract [Member]
 
 
Derivative assets
3 1 2
3 1 2
Derivative liabilities
18 1 2
21 1 2
Natural Gas [Member] |
Fair Value, Inputs, Level 3 [Member] |
Commodity Contract [Member]
 
 
Derivative assets
3 1 2
2 1 2
Derivative liabilities
120 1 2
150 1 2
Natural Gas [Member] |
Commodity Contract [Member]
 
 
Derivative assets
6 1 2
5 1 2
Derivative liabilities
138 1 2
171 1 2
Power [Member] |
Fair Value, Inputs, Level 2 [Member] |
Commodity Contract [Member]
 
 
Derivative assets
18 1 2
17 1 2
Derivative liabilities
16 1 2
19 1 2
Power [Member] |
Fair Value, Inputs, Level 3 [Member] |
Commodity Contract [Member]
 
 
Derivative assets
174 1 2
86 1 2
Derivative liabilities
57 1 2
50 1 2
Power [Member] |
Commodity Contract [Member]
 
 
Derivative assets
192 1 2
103 1 2
Derivative liabilities
73 1 2
69 1 2
Uranium [Member] |
Fair Value, Inputs, Level 3 [Member] |
Commodity Contract [Member]
 
 
Derivative assets
 
2 1 2
Derivative liabilities
2 1 2
 
Uranium [Member] |
Commodity Contract [Member]
 
 
Derivative assets
 
2 1 2
Derivative liabilities
2 1 2
 
Fair Value, Inputs, Level 1 [Member] |
Equity Securities [Member] |
US Large Capitalization [Member]
 
 
Nuclear Decommissioning Trust Fund
234 1 3
228 1 3
Fair Value, Inputs, Level 1 [Member] |
Cash and Cash Equivalents [Member]
 
 
Nuclear Decommissioning Trust Fund
1 1 3
1 1 3
Fair Value, Inputs, Level 2 [Member] |
Debt Securities [Member] |
Municipal Bonds [Member]
 
 
Nuclear Decommissioning Trust Fund
2 1 3
2 1 3
Fair Value, Inputs, Level 2 [Member] |
Debt Securities [Member] |
Other Debt Obligations [Member]
 
 
Nuclear Decommissioning Trust Fund
1 1 3
1 1 3
Fair Value, Inputs, Level 2 [Member] |
Debt Securities [Member] |
US Treasury and Government [Member]
 
 
Nuclear Decommissioning Trust Fund
59 1 3
50 1 3
Fair Value, Inputs, Level 2 [Member] |
Debt Securities [Member] |
Corporate Debt Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
45 1 3
40 1 3
Fair Value, Inputs, Level 2 [Member] |
Debt Securities [Member] |
Asset-backed Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
13 1 3
14 1 3
Equity Securities [Member] |
US Large Capitalization [Member]
 
 
Nuclear Decommissioning Trust Fund
234 1 3
228 1 3
Debt Securities [Member] |
Municipal Bonds [Member]
 
 
Nuclear Decommissioning Trust Fund
2 1 3
2 1 3
Debt Securities [Member] |
Other Debt Obligations [Member]
 
 
Nuclear Decommissioning Trust Fund
1 1 3
1 1 3
Debt Securities [Member] |
US Treasury and Government [Member]
 
 
Nuclear Decommissioning Trust Fund
59 1 3
50 1 3
Debt Securities [Member] |
Corporate Debt Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
45 1 3
40 1 3
Debt Securities [Member] |
Asset-backed Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
13 1 3
14 1 3
Cash and Cash Equivalents [Member]
 
 
Nuclear Decommissioning Trust Fund
$ 1 1 3
$ 1 1 3
Fair Value Measurements (Schedule of Changes in the Fair Value of Financial Assets and Liabilities Classified as Level 3 in the Fair Value Hierarchy) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Heating Oil [Member]
 
 
 
 
Beginning balance
$ 96 
$ 54 
$ 51 
$ 60 
Included in earnings
(5)1
(8)1
17 1
(10)1
Included in regulatory assets/liabilities
(9)
(9)
22 
(11)
Total realized and unrealized gains (losses)
(14)
(17)
39 
(21)
Purchases
1 
33 
2 
32 
Settlements
(15)
(41)
(24)
(42)
Ending Balance
68 
29 
68 
29 
Change in unrealized gains (losses) related to assets/liabilities still held
(14)
(16)
30 
(18)
Natural Gas [Member]
 
 
 
 
Beginning balance
(120)
(162)
(148)
(67)
Included in earnings
 1
 
 
 
Included in regulatory assets/liabilities
(20)
(6)
(13)
(109)
Total realized and unrealized gains (losses)
(20)
(6)
(13)
(109)
Purchases
1 
 
1 
(4)
Settlements
22 
30 
43 
42 
Ending Balance
(117)
(138)
(117)
(138)
Change in unrealized gains (losses) related to assets/liabilities still held
(18)
(6)
9 
(81)
Power [Member]
 
 
 
 
Beginning balance
31 
37 
36 
38 
Included in earnings
(15)1
6 1
(18)1
24 1
Included in OCI
5 
(18)
5 
6 
Included in regulatory assets/liabilities
66 
29 
64 
7 
Total realized and unrealized gains (losses)
56 
17 
51 
37 
Purchases
50 
25 
59 
38 
Sales
(7)
2 
(16)
(5)
Settlements
(16)
(19)
(16)
(29)
Transfers into Level 3
1 
(1)
1 
(1)
Transfers out of Level 3
2 
(7)
2 
(24)
Ending Balance
117 
54 
117 
54 
Change in unrealized gains (losses) related to assets/liabilities still held
59 
(5)
59 
(7)
Uranium [Member]
 
 
 
 
Beginning balance
1 
(3)
2 
(2)
Included in regulatory assets/liabilities
(3)
(1)
(4)
(2)
Total realized and unrealized gains (losses)
(3)
(1)
(4)
(2)
Ending Balance
(2)
(4)
(2)
(4)
Change in unrealized gains (losses) related to assets/liabilities still held
$ (2)
 
$ (2)
$ (1)
Fair Value Measurements (Schedule of Carrying Amounts and Estimated Fair Values of Long-Term Debt and Capital Lease Obligations and Preferred Stock) (Details) (USD $)
In Millions, unless otherwise specified
Jun. 30, 2011
Dec. 31, 2010
Noncontrolling interest
20.00% 
 
Carrying Amount [Member]
 
 
Long-term debt and capital lease obligations (including current portion)
$ 6,859 1 2
$ 7,008 1 2
Preferred stock
142 1 2
142 1 2
Estimated of Fair Value [Member]
 
 
Long-term debt and capital lease obligations (including current portion)
7,666 1 2
7,661 1 2
Preferred stock
$ 102 1 2
$ 102 1 2
Commitments and Contingencies (Callaway Nuclear Energy Center) (Details) (USD $)
6 Months Ended
Jun. 30, 2011
years
weeks
Threshold for which a retrospective assessment for a covered loss is necessary
$ 375,000,000 
Annual payment in the event of an incident at any licensed commercial reactor
17,500,000 
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act
118,000,000 
Maximum annual payment to be paid in a calendar year per reactor incident under liability provisions of Atomic Energy Act
17,500,000 
Amount of primary property liability coverage
500,000,000 
Amount of coverage in excess of primary property liability coverage
2,250,000,000 
Amount of weekly indemnity coverage commencing eight weeks after power outage
4,500,000 
Number of weeks of coverage after the first eight weeks of an outage
52 
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage
3,600,000 
Amount of weekly indemnity coverage thereafter not exceeding policy limit
490,000,000 
Number of additional weeks after initial indemnity coverage for power outage, minimum
71 
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 
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period
3,240,000,000 
Maximum Coverage [Member]
 
Insurance aggregate maximum coverage
12,594,000,000 1
Maximum Coverage [Member] |
Public Liability and Nuclear Worker Liability - American Nuclear Insurers [Member]
 
Insurance aggregate maximum coverage
375,000,000 
Maximum Coverage [Member] |
Public Liability and Nuclear Worker Liability - Pool Participation [Member]
 
Insurance aggregate maximum coverage
12,219,000,000 2
Maximum Coverage [Member] |
Property Damage - Nuclear Electric Insurance Ltd [Member]
 
Insurance aggregate maximum coverage
2,750,000,000 3
Maximum Coverage [Member] |
Replacement Power - Nuclear Electric Insurance Ltd [Member]
 
Insurance aggregate maximum coverage
490,000,000 4
Maximum Coverage [Member] |
Replacement Power - Energy Risk Assurance Company [Member]
 
Insurance aggregate maximum coverage
64,000,000 5
Maximum Assessments for Single Incidents [Member]
 
Insurance maximum coverage per incident
118,000,000 
Maximum Assessments for Single Incidents [Member] |
Public Liability and Nuclear Worker Liability - American Nuclear Insurers [Member]
 
Insurance maximum coverage per incident
 
Maximum Assessments for Single Incidents [Member] |
Public Liability and Nuclear Worker Liability - Pool Participation [Member]
 
Insurance maximum coverage per incident
118,000,000 6
Maximum Assessments for Single Incidents [Member] |
Property Damage - Nuclear Electric Insurance Ltd [Member]
 
Insurance maximum coverage per incident
23,000,000 
Maximum Assessments for Single Incidents [Member] |
Replacement Power - Nuclear Electric Insurance Ltd [Member]
 
Insurance maximum coverage per incident
9,000,000 
Maximum Assessments for Single Incidents [Member] |
Replacement Power - Energy Risk Assurance Company [Member]
 
Insurance maximum coverage per incident
 
Commitments and Contingencies (Schedule of Estimated Purchased Power Commitments) (Details) (USD $)
In Millions
6 Months Ended
Jun. 30, 2011
Coal Agreement 2011 [Member]
 
Long-term commitments
$ 669 
Coal Agreement 2012 [Member]
 
Long-term commitments
1,153 
Coal Agreement 2013 [Member]
 
Long-term commitments
801 
Coal Agreement 2014 [Member]
 
Long-term commitments
643 
Coal Agreement 2015 [Member]
 
Long-term commitments
634 
Coal Agreement Thereafter [Member]
 
Long-term commitments
1,651 
Purchased Power Commitments 2011 [Member]
 
Long-term commitments
178 
Purchased Power Commitments 2012 [Member]
 
Long-term commitments
200 
Purchased Power Commitments 2013 [Member]
 
Long-term commitments
314 
Purchased Power Commitments 2014 [Member]
 
Long-term commitments
129 
Purchased Power Commitments 2015 [Member]
 
Long-term commitments
55 
Purchased Power Commitments Thereafter [Member]
 
Long-term commitments
$ 826 
Commitments and Contingencies (Environmental Matters) (Details) (USD $)
Jun. 30, 2011
properties
Dec. 31, 2010
MACT standard emission limits based on existing coal and oil-fired generating units, percentage
12.00% 
 
Reduction in mercury emissions included in the proposed federal MACT standard
91.00% 
 
Number of states included in the CAIR regulations
28 
 
Number of states included in CSAPR
23 
 
Expected percentage reduction in SO2 emissions by 2014 included in CSAPR
73.00% 
 
Expected percentage reduction in NOx emissions by 2014 included in the proposed transport rule
54.00% 
 
Threshold amount of greenhouse emissions in tons that will require operating permit under title V operating permit program of the Clean Air Act
75,000 
 
Threshold, in millions of gallons of water per day, for power plants to be regulated under the EPA's proposed Clean Water Act rules
2 
 
Threshold, in percentage, of water used for cooling at a power plant to be regulated under the EPA's proposed Clean Water Act rules
25.00% 
 
Level of intake velocity (feet per second) included in the EPA's proposed Clean Water Act rules
0.5 
 
Property, plant and equipment, net
$ 17,945,000,000 
$ 17,853,000,000 
Hutsonville [Member]
 
 
Property, plant and equipment, net
26,000,000 
 
Meredosia [Member]
 
 
Property, plant and equipment, net
1,000,000 
 
Unit One, E.D. Edwards Energy Center [Member]
 
 
Property, plant and equipment, net
18,000,000 
 
Minimum [Member] |
Estimated Capital Costs 2016 - 2020 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
975,000,000 
 
Minimum [Member] |
Estimated Capital Costs 2011 Through 2020[Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
1,990,000,000 
 
Maximum [Member] |
Estimated Capital Costs 2012 - 2015 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
1,035,000,000 
 
Maximum [Member] |
Estimated Capital Costs 2016 - 2020 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
1,195,000,000 
 
Maximum [Member] |
Estimated Capital Costs 2011 Through 2020[Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
2,405,000,000 
 
Ameren Missouri [Member] |
Manufactured Gas Plant [Member]
 
 
Number of remediation sites
10 
 
Ameren Illinois [Member] |
Manufactured Gas Plant [Member]
 
 
Number of remediation sites
44 
 
Manufactured Gas Plant [Member]
 
 
Loss contingency range of possible loss minimum
121,000,000 
 
Loss contingency range of possible loss maximum
199,000,000 
 
Accrual for environmental loss contingencies
121,000,000 1
 
Manufactured Gas Plant [Member] |
Iowa [Member]
 
 
Number of remediation sites
1 
 
Ameren Illinois [Member] |
Former Coal Ash Landfill [Member]
 
 
Loss contingency range of possible loss minimum
500,000 
 
Loss contingency range of possible loss maximum
6,000,000 
 
Accrual for environmental loss contingencies
500,000 
 
Ameren Illinois [Member] |
Other Environmental [Member]
 
 
Accrual for environmental loss contingencies
800,000 
 
Ameren Missouri [Member] |
Former Coal Tar Distillery [Member]
 
 
Loss contingency range of possible loss minimum
2,000,000 
 
Loss contingency range of possible loss maximum
5,000,000 
 
Accrual for environmental loss contingencies
2,000,000 
 
Ameren Missouri [Member] |
Sauget Area 2 [Member]
 
 
Loss contingency range of possible loss minimum
400,000 
 
Loss contingency range of possible loss maximum
10,000,000 
 
Accrual for environmental loss contingencies
400,000 
 
Estimated Capital Costs [Member]
 
 
Reduction in capital expenditure estimate for environmental compliance
1,100,000,000 
 
Estimated Capital Costs 2011 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
175,000,000 
 
Ameren Illinois [Member]
 
 
Property, plant and equipment, net
$ 4,657,000,000 
$ 4,576,000,000 
Commitments and Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Details) (USD $)
In Millions
79 Months Ended
Jun. 30, 2011
Sep. 30, 2011
Commitments and Contingencies
 
 
Payments relating to Taum Sauk incident damage and cleanup
$ 208 
 
Payments relating to Taum Sauk incident damage and cleanup recorded to expense and not covered by insurance
36 
 
Cumulative payments relating to Taum Sauk incident damage and cleanup covered by insurance and recorded as a receivable
172 
 
Cumulative liability insurance reimbursements received for Taum Sauk incident
104 
 
Insurance settlements receivable
68 
 
Disallowed capitalized costs associated with rebuilt Taum Sauk energy center
 
$ 89 
Callaway Energy Center (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31,
6 Months Ended
Jun. 30, 2011
years
weeks
properties
2010
2009
2008
Number of mills charged for NWF fee
1 
 
 
 
Costs incurred to be recovered
$ 13 
 
 
 
Settlement payment
11 
 
 
 
Assumed life of plant, in years
40 
 
 
 
Annual decommissioning costs included in costs of service
 
7 
7 
7 
Reduction To Depreciation And Amortization [Member]
 
 
 
 
Settlement payment
2 
 
 
 
Reduction To Other Operations And Maintenance [Member]
 
 
 
 
Settlement payment
2 
 
 
 
Reduction In Property And Plant [Member]
 
 
 
 
Settlement payment
$ 7 
 
 
 
Other Comprehensive Income (Schedule of Comprehensive Income) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Other Comprehensive Income
 
 
 
 
Net income
$ 139 1
$ 155 1
$ 213 1
$ 261 1
Unrealized net gain (loss) on derivative hedging instruments, net of taxes (benefit)
(8)1
(11)1
(6)1
17 1
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes
7 1
(5)1
3 1
(20)1
Pension and other postretirement activity, net of income taxes (benefit)
 1
7 1
(1)1
6 1
Total comprehensive income, net of taxes
138 1
146 1
209 1
264 1
Less: Net income attributable to noncontrolling interests, net of taxes
1 1
3 1
4 1
7 1
Total comprehensive income attributable to Ameren Corporation, net of taxes
$ 137 1
$ 143 1
$ 205 1
$ 257 1
Other Comprehensive Income (Parenthetical) (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Other Comprehensive Income
 
 
 
 
Unrealized net gain (loss) on derivative hedging instruments, tax (benefit)
$ (5)
$ (7)
$ (4)
$ 11 
Reclassification adjustments for derivative (gain) included in net income, tax
(4)
3 
(2)
12 
Pension and other postretirement activity, tax (benefit)
$ (1)
$ 5 
$ (2)
$ 6 
Retirement Benefits (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Defined benefit plan estimated future employer contributions over the next five years
$ 470 
 
$ 470 
 
Minimum [Member]
 
 
 
 
Defined benefit plan estimated future employer contributions in each of the next five years
75 
 
75 
 
Maximum [Member]
 
 
 
 
Defined benefit plan estimated future employer contributions in each of the next five years
110 
 
110 
 
Pension Benefits [Member]
 
 
 
 
Service cost
18 1
16 1
38 1
33 1
Interest cost
45 1
46 1
90 1
93 1
Expected return on plan assets
(54)1
(53)1
(108)1
(106)1
Amortization of transition obligation
 1
 1
 1
 1
Amortization of prior service cost (benefit)
(1)1
2 1
(1)1
4 1
Amortization of actuarial loss (gain)
10 1
4 1
21 1
9 1
Net periodic benefit cost
18 1
15 1
40 1
33 1
Postretirement Benefits [Member]
 
 
 
 
Service cost
5 1
5 1
11 1
10 1
Interest cost
14 1
14 1
29 1
30 1
Expected return on plan assets
(13)1
(14)1
(27)1
(28)1
Amortization of transition obligation
1 1
1 1
1 1
1 1
Amortization of prior service cost (benefit)
(2)1
(2)1
(4)1
(4)1
Amortization of actuarial loss (gain)
1 1
(1)1
2 1
1 1
Net periodic benefit cost
$ 6 1
$ 3 1
$ 12 1
$ 10 1
Segment Information (Details) (USD $)
In Millions
3 Months Ended
Jun. 30,		 6 Months Ended
Jun. 30,
2011
2010
2011
2010
Dec. 31, 2010
External revenues
$ 1,781 
$ 1,725 
$ 3,685 
$ 3,665 
 
Net income (loss) attributable to Ameren Corporation
138 1
152 1
209 1
254 1
 
Total assets
23,391 
 
23,391 
 
23,515 
Ameren Missouri [Member]
 
 
 
 
 
External revenues
814 
756 
1,581 
1,433 
 
Intersegment revenues
8 
5 
13 
10 
 
Net income (loss) attributable to Ameren Corporation
90 1
113 1
111 1
140 1
 
Total assets
12,527 
 
12,527 
 
12,504 
Ameren Illinois [Member]
 
 
 
 
 
External revenues
619 
644 
1,424 
1,553 
 
Intersegment revenues
4 
3 
7 
5 
 
Net income (loss) attributable to Ameren Corporation
37 1
46 1
70 1
81 1
 
Total assets
7,154 
 
7,154 
 
7,406 
Merchant Generation [Member]
 
 
 
 
 
External revenues
347 
325 
679 
679 
 
Intersegment revenues
49 
60 
96 
134 
 
Net income (loss) attributable to Ameren Corporation
15 1
(2)1
35 1
42 1
 
Total assets
3,861 
 
3,861 
 
3,934 
Other [Member]
 
 
 
 
 
External revenues
1 
 
1 
 
 
Intersegment revenues
 
3 
1 
6 
 
Net income (loss) attributable to Ameren Corporation
(4)1
(5)1
(7)1
(9)1
 
Total assets
1,324 
 
1,324 
 
1,354 
Intersegment Eliminations [Member]
 
 
 
 
 
Intersegment revenues
(61)
(71)
(117)
(155)
 
Total assets
$ (1,475)
 
$ (1,475)
 
$ (1,683)