UNION ELECTRIC CO, 10-Q filed on 5/10/2012
Quarterly Report
Document And Entity Information
3 Months Ended
Mar. 31, 2012
Apr. 30, 2012
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Mar. 31, 2012 
 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q1 
 
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
 
242,634,671 
Union Electric Company [Member]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Mar. 31, 2012 
 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q1 
 
Entity Registrant Name
UNION ELECTRIC CO 
 
Entity Central Index Key
0000100826 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
102,123,834 
Ameren Illinois Company [Member]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Mar. 31, 2012 
 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q1 
 
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
Mar. 31, 2012 
 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q1 
 
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 (Loss) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Operating Revenues:
 
 
Electric
$ 1,310 
$ 1,470 
Gas
348 
434 
Total operating revenues
1,658 
1,904 
Operating Expenses:
 
 
Fuel
327 
379 
Purchased power
163 
227 
Gas purchased for resale
215 
288 
Other operations and maintenance
427 
463 
Asset impairment
628 
   
Depreciation and amortization
199 
195 
Taxes other than income taxes
121 
125 
Total operating expenses
2,080 
1,677 
Operating Income (Loss)
(422)
227 
Other Income and Expenses:
 
 
Miscellaneous income
17 1
16 1
Miscellaneous expense
15 1
5 1
Total other income (expense)
2 
11 
Interest Charges
113 
119 
Income (Loss) Before Income Taxes (Benefit)
(533)
119 
Income Taxes (Benefit)
(130)
45 
Net Income (Loss)
(403)
74 
Less: Net Income Attributable to Noncontrolling Interests
 
3 
Net Income(Loss)
(403)2
71 2
Earnings (Loss) per Common Share - Basic and Diluted
$ (1.66)
$ 0.29 
Dividends per Common Share
$ 0.40 
$ 0.385 
Average Common Shares Outstanding
242.6 
240.6 
Union Electric Company [Member]
 
 
Operating Revenues:
 
 
Electric
636 
702 
Gas
55 
69 
Other
 
1 
Total operating revenues
691 
772 
Operating Expenses:
 
 
Fuel
180 
229 
Purchased power
20 
20 
Gas purchased for resale
32 
40 
Other operations and maintenance
202 
233 
Depreciation and amortization
108 
100 
Taxes other than income taxes
71 
73 
Total operating expenses
613 
695 
Operating Income (Loss)
78 
77 
Other Income and Expenses:
 
 
Miscellaneous income
15 
13 
Miscellaneous expense
3 
3 
Total other income (expense)
12 
10 
Interest Charges
56 
54 
Income (Loss) Before Income Taxes (Benefit)
34 
33 
Income Taxes (Benefit)
12 
11 
Net Income (Loss)
22 
22 
Preferred Stock Dividends
1 
1 
Net Income Available to Common Stockholder
21 
21 
Ameren Illinois Company [Member]
 
 
Operating Revenues:
 
 
Electric
431 
442 
Gas
293 
366 
Total operating revenues
724 
808 
Operating Expenses:
 
 
Purchased power
190 
211 
Gas purchased for resale
183 
248 
Other operations and maintenance
168 
168 
Depreciation and amortization
55 
52 
Taxes other than income taxes
39 
41 
Total operating expenses
635 
720 
Operating Income (Loss)
89 
88 
Other Income and Expenses:
 
 
Miscellaneous income
1 
2 
Miscellaneous expense
11 
1 
Total other income (expense)
(10)
1 
Interest Charges
33 
35 
Income (Loss) Before Income Taxes (Benefit)
46 
54 
Income Taxes (Benefit)
18 
20 
Net Income (Loss)
28 
34 
Preferred Stock Dividends
1 
1 
Net Income Available to Common Stockholder
27 
33 
Ameren Energy Generating Company [Member]
 
 
Operating Revenues:
 
 
Total operating revenues
194 
241 
Operating Expenses:
 
 
Fuel
105 
111 
Other operations and maintenance
47 
45 
Depreciation and amortization
23 
24 
Taxes other than income taxes
6 
7 
Total operating expenses
181 
187 
Operating Income (Loss)
13 
54 
Other Income and Expenses:
 
 
Interest Charges
14 
17 
Income (Loss) Before Income Taxes (Benefit)
(1)
37 
Income Taxes (Benefit)
2 
15 
Net Income (Loss)
(3)
22 
Less: Net Income Attributable to Noncontrolling Interests
(2)
1 
Net Income(Loss)
$ (1)
$ 21 
Consolidated Balance Sheet (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Current Assets:
 
 
Cash and cash equivalents
$ 208 
$ 255 
Accounts receivable - trade (less allowance for doubtful accounts)
446 
473 
Unbilled revenue
232 
324 
Miscellaneous accounts and notes receivable
65 
69 
Materials and supplies
625 
712 
Mark-to-market derivative assets
167 
115 
Current regulatory assets
247 
215 
Other current assets
134 
132 
Total current assets
2,124 
2,295 
Property and Plant, Net
17,535 
18,127 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
390 
357 
Goodwill
411 
411 
Intangible assets
9 
7 
Regulatory assets
1,657 
1,603 
Other assets
773 
845 
Total investments and other assets
3,240 
3,223 
TOTAL ASSETS
22,899 
23,645 
Current Liabilities:
 
 
Current maturities of long-term debt
179 
179 
Short-term debt
126 
148 
Accounts and wages payable
366 
693 
Taxes accrued
101 
65 
Interest accrued
149 
101 
Customer deposits
98 
98 
Mark-to-market derivative liabilities
220 
161 
Current regulatory liabilities
138 
133 
Other current liabilities
237 
207 
Total current liabilities
1,614 
1,785 
Long-term Debt, Net
6,677 
6,677 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
3,111 
3,315 
Accumulated deferred investment tax credits
77 
79 
Regulatory liabilities
1,483 
1,502 
Asset retirement obligations
434 
428 
Pension and other postretirement benefits
1,357 
1,344 
Other deferred credits and liabilities
567 
447 
Total deferred credits and other liabilities
7,029 
7,115 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
   
   
Stockholders' Equity:
 
 
Common stock
2 
2 
Other paid-in capital, principally premium on common stock
5,596 
5,598 
Retained earnings
1,869 
2,369 
Accumulated other comprehensive income (loss)
(35)
(50)
Total stockholders' equity
7,432 
7,919 
Noncontrolling Interests
147 
149 
Total equity
7,579 
8,068 
TOTAL LIABILITIES AND EQUITY
22,899 
23,645 
Union Electric Company [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
3 
201 
Accounts receivable - trade (less allowance for doubtful accounts)
170 
212 
Accounts receivable - affiliates
3 
1 
Unbilled revenue
110 
139 
Miscellaneous accounts and notes receivable
41 
42 
Materials and supplies
365 
348 
Mark-to-market derivative assets
59 
49 
Current regulatory assets
113 
109 
Other current assets
24 
33 
Total current assets
888 
1,134 
Property and Plant, Net
9,976 
9,958 
Investments and Other Assets:
 
 
Nuclear decommissioning trust fund
390 
357 
Intangible assets
9 
7 
Regulatory assets
842 
855 
Other assets
441 
446 
Total investments and other assets
1,682 
1,665 
TOTAL ASSETS
12,546 
12,757 
Current Liabilities:
 
 
Current maturities of long-term debt
178 
178 
Accounts and wages payable
142 
414 
Accounts payable - affiliates
107 
73 
Taxes accrued
113 
74 
Interest accrued
58 
62 
Current regulatory liabilities
60 
57 
Other current liabilities
120 
84 
Total current liabilities
778 
942 
Long-term Debt, Net
3,772 
3,772 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
2,115 
2,132 
Accumulated deferred investment tax credits
68 
70 
Regulatory liabilities
874 
836 
Asset retirement obligations
333 
328 
Pension and other postretirement benefits
498 
491 
Other deferred credits and liabilities
150 
149 
Total deferred credits and other liabilities
4,038 
4,006 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
   
   
Stockholders' Equity:
 
 
Common stock
511 
511 
Other paid-in capital, principally premium on common stock
1,555 
1,555 
Preferred stock not subject to mandatory redemption
80 
80 
Retained earnings
1,812 
1,891 
Total stockholders' equity
3,958 
4,037 
TOTAL LIABILITIES AND EQUITY
12,546 
12,757 
Ameren Illinois Company [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
187 
21 
Accounts receivable - trade (less allowance for doubtful accounts)
228 
201 
Accounts receivable - affiliates
12 
15 
Unbilled revenue
92 
146 
Miscellaneous accounts and notes receivable
6 
6 
Materials and supplies
96 
199 
Current regulatory assets
316 
306 
Counterparty collateral asset
70 
50 
Current accumulated deferred income taxes, net
43 
58 
Other current assets
11 
15 
Total current assets
1,061 
1,017 
Property and Plant, Net
4,804 
4,770 
Investments and Other Assets:
 
 
Tax receivable - Genco
51 
56 
Goodwill
411 
411 
Regulatory assets
814 
748 
Other assets
115 
211 
Total investments and other assets
1,391 
1,426 
TOTAL ASSETS
7,256 
7,213 
Current Liabilities:
 
 
Current maturities of long-term debt
1 
1 
Accounts and wages payable
115 
133 
Accounts payable - affiliates
98 
103 
Taxes accrued
15 
15 
Interest accrued
50 
22 
Customer deposits
76 
76 
Mark-to-market derivative liabilities
122 
99 
Mark-to-market derivative liabilities - affiliates
183 
200 
Environmental remediation
25 
63 
Current regulatory liabilities
78 
76 
Other current liabilities
57 
70 
Total current liabilities
820 
858 
Long-term Debt, Net
1,657 
1,657 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
934 
895 
Accumulated deferred investment tax credits
6 
7 
Regulatory liabilities
608 
666 
Pension and other postretirement benefits
499 
495 
Other deferred credits and liabilities
291 
183 
Total deferred credits and other liabilities
2,338 
2,246 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
   
   
Stockholders' Equity:
 
 
Common stock
   
   
Other paid-in capital, principally premium on common stock
1,965 
1,965 
Preferred stock not subject to mandatory redemption
62 
62 
Retained earnings
398 
408 
Accumulated other comprehensive income (loss)
16 
17 
Total stockholders' equity
2,441 
2,452 
TOTAL LIABILITIES AND EQUITY
7,256 
7,213 
Ameren Energy Generating Company [Member]
 
 
Current Assets:
 
 
Cash and cash equivalents
 
8 
Advances to money pool
95 
74 
Accounts receivable - affiliates
58 
89 
Miscellaneous accounts and notes receivable
14 
13 
Materials and supplies
121 
122 
Mark-to-market derivative assets
13 
12 
Other current assets
10 
7 
Total current assets
311 
325 
Property and Plant, Net
2,242 
2,231 
Investments and Other Assets:
 
 
Other assets
18 
16 
TOTAL ASSETS
2,571 
2,572 
Current Liabilities:
 
 
Accounts and wages payable
60 
71 
Accounts payable - affiliates
14 
13 
Current portion of tax payable - Ameren Illinois
10 
8 
Taxes accrued
21 
20 
Interest accrued
27 
13 
Current accumulated deferred income taxes, net
8 
 
Other current liabilities
18 
17 
Total current liabilities
158 
142 
Long-term Debt, Net
824 
824 
Deferred Credits and Other Liabilities:
 
 
Accumulated deferred income taxes, net
291 
304 
Accumulated deferred investment tax credits
2 
2 
Tax payable - Ameren Illinois
51 
56 
Asset retirement obligations
67 
66 
Pension and other postretirement benefits
140 
141 
Other deferred credits and liabilities
15 
12 
Total deferred credits and other liabilities
566 
581 
Commitments and Contingencies (Notes 2, 8, 9 and 10)
   
   
Stockholders' Equity:
 
 
Common stock
   
   
Other paid-in capital, principally premium on common stock
653 
653 
Retained earnings
436 
437 
Accumulated other comprehensive income (loss)
(71)
(72)
Total stockholders' equity
1,018 
1,018 
Noncontrolling Interests
5 
7 
Total equity
1,023 
1,025 
TOTAL LIABILITIES AND EQUITY
$ 2,571 
$ 2,572 
Consolidated Balance Sheet (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Accounts receivable - trade, allowance for doubtful accounts
$ 24 
$ 20 
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
400,000,000 
400,000,000 
Common stock, shares outstanding
242,600,000 
242,600,000 
Union Electric Company [Member]
 
 
Accounts receivable - trade, allowance for doubtful accounts
9 
7 
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 Company [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, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Cash Flows From Operating Activities:
 
 
Net income (loss)
$ (403)
$ 74 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Loss on asset impairment
628 
   
Depreciation and amortization
188 
187 
Amortization of nuclear fuel
21 
17 
Amortization of debt issuance costs and premium/discounts
5 
5 
Deferred income taxes and investment tax credits, net
(142)
(16)
Allowance for equity funds used during construction
(9)1
(6)1
Net mark-to-market (gain) loss on derivatives
(3)
(16)
Other
(5)
   
Changes in assets and liabilities:
 
 
Receivables
109 
94 
Materials and supplies
80 
135 
Accounts and wages payable
(220)
(213)
Taxes accrued
35 
71 
Assets, other
14 
50 
Liabilities, other
64 
80 
Pension and other postretirement benefits
41 
28 
Counterparty collateral, net
(11)
70 
Net cash provided by operating activities
392 
560 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(282)
(231)
Nuclear fuel expenditures
(38)
(22)
Purchases of securities - nuclear decommissioning trust fund
(109)
(91)
Sales of securities - nuclear decommissioning trust fund
88 
87 
Proceeds from sale of property
16 
   
Other
(1)
1 
Net cash used in investing activities
(326)
(256)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(90)
(93)
Dividends paid to noncontrolling interest holders
(2)
(2)
Short-term debt and credit facility borrowings, net
(22)
(125)
Generator advances received for construction
1 
   
Repayments of generator advances received for construction
 
(73)
Issuances of common stock
 
17 
Net cash Provided by (used in) financing activities
(113)
(276)
Net change in cash and cash equivalents
(47)
28 
Cash and cash equivalents at beginning of year
255 
545 
Cash and cash equivalents at end of period
208 
573 
Noncash financing activity - dividends on common stock
(7)
   
Union Electric Company [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income (loss)
22 
22 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
100 
93 
Amortization of nuclear fuel
21 
17 
Amortization of debt issuance costs and premium/discounts
2 
2 
Deferred income taxes and investment tax credits, net
2 
9 
Allowance for equity funds used during construction
(8)
(6)
Net mark-to-market (gain) loss on derivatives
 
1 
Changes in assets and liabilities:
 
 
Receivables
61 
16 
Materials and supplies
(26)
14 
Accounts and wages payable
(136)
(144)
Taxes accrued
39 
(1)
Assets, other
13 
29 
Liabilities, other
14 
14 
Pension and other postretirement benefits
17 
14 
Net cash provided by operating activities
121 
80 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(157)
(129)
Nuclear fuel expenditures
(38)
(22)
Purchases of securities - nuclear decommissioning trust fund
(109)
(91)
Sales of securities - nuclear decommissioning trust fund
88 
87 
Other
(2)
(1)
Net cash used in investing activities
(218)
(156)
Cash Flows From Financing Activities:
 
 
Dividends on common stock
(100)
(68)
Dividends on preferred stock
(1)
(1)
Generator advances received for construction
 
(19)
Net cash Provided by (used in) financing activities
(101)
(88)
Net change in cash and cash equivalents
(198)
(164)
Cash and cash equivalents at beginning of year
201 
202 
Cash and cash equivalents at end of period
3 
38 
Ameren Illinois Company [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income (loss)
28 
34 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
52 
50 
Amortization of debt issuance costs and premium/discounts
2 
2 
Deferred income taxes and investment tax credits, net
55 
(31)
Other
(2)
(1)
Changes in assets and liabilities:
 
 
Receivables
35 
42 
Materials and supplies
103 
123 
Accounts and wages payable
(16)
(47)
Taxes accrued
 
46 
Assets, other
2 
12 
Liabilities, other
26 
42 
Pension and other postretirement benefits
15 
11 
Counterparty collateral, net
(11)
32 
Net cash provided by operating activities
289 
315 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(86)
(69)
Returns of advances from ATXI for construction
 
49 
Other
 
1 
Net cash used in investing activities
(86)
(19)
Cash Flows From Financing Activities:
 
 
Capital contribution from parent
 
6 
Dividends on common stock
(37)
(62)
Dividends on preferred stock
(1)
(1)
Generator advances received for construction
1 
 
Repayments of generator advances received for construction
 
(53)
Net cash Provided by (used in) financing activities
(37)
(110)
Net change in cash and cash equivalents
166 
186 
Cash and cash equivalents at beginning of year
21 
322 
Cash and cash equivalents at end of period
187 
508 
Noncash investing activity - asset transfer from ATXI
 
20 
Ameren Energy Generating Company [Member]
 
 
Cash Flows From Operating Activities:
 
 
Net income (loss)
(3)
22 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation and amortization
23 
25 
Amortization of debt issuance costs and premium/discounts
1 
1 
Deferred income taxes and investment tax credits, net
(7)
13 
Net mark-to-market (gain) loss on derivatives
(1)
(15)
Other
5 
 
Changes in assets and liabilities:
 
 
Receivables
27 
18 
Materials and supplies
(1)
4 
Accounts and wages payable
(9)
(16)
Taxes accrued
1 
17 
Assets, other
(4)
(3)
Liabilities, other
13 
12 
Pension and other postretirement benefits
1 
(2)
Net cash provided by operating activities
46 
76 
Cash Flows From Investing Activities:
 
 
Capital expenditures
(33)
(35)
Money pool advances, net
(21)
(65)
Net cash used in investing activities
(54)
(100)
Cash Flows From Financing Activities:
 
 
Capital contribution from parent
 
24 
Net cash Provided by (used in) financing activities
 
24 
Net change in cash and cash equivalents
(8)
 
Cash and cash equivalents at beginning of year
8 
6 
Cash and cash equivalents at end of period
 
$ 6 
Consolidated Statement of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Net income (Loss)
$ (403)
$ 74 
Other Comprehensive Income (Loss), Net of Taxes [Abstract]
 
 
Unrealized net gain on derivative hedging instruments, net of income taxes
12 
2 
Reclassification adjustments for derivative (gains) losses included in net income, net of income taxes (benefit)
2 
(4)
Pension and other postretirement activity, net of income taxes
1 
(1)
Total other comprehensive income (loss), net of taxes
15 
(3)
Comprehensive Income (Loss)
(388)
71 
Less: Comprehensive Income Attributable to Noncontrolling Interests
 
3 
Comprehensive Income (Loss)
(388)
68 
Union Electric Company [Member]
 
 
Net income (Loss)
22 
22 
Other Comprehensive Income (Loss), Net of Taxes [Abstract]
 
 
Comprehensive Income (Loss)
22 
22 
Ameren Illinois Company [Member]
 
 
Net income (Loss)
28 
34 
Other Comprehensive Income (Loss), Net of Taxes [Abstract]
 
 
Pension and other postretirement activity, net of income taxes
(1)
(1)
Comprehensive Income (Loss)
27 
33 
Ameren Energy Generating Company [Member]
 
 
Net income (Loss)
(3)
22 
Other Comprehensive Income (Loss), Net of Taxes [Abstract]
 
 
Pension and other postretirement activity, net of income taxes
1 
1 
Total other comprehensive income (loss), net of taxes
1 
1 
Comprehensive Income (Loss)
(2)
23 
Comprehensive Income (Loss)
$ (2)
$ 23 
Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Consolidated Statement Of Comprehensive Income [Abstract]
 
 
Unrealized net gain (loss) on derivative hedging instruments, tax
$ 7 
$ 1 
Reclassification adjustments for derivative (gain) included in net income, tax (benefit)
(1)
2 
Pension and other postretirement benefit plan activity, tax (benefit)
    
$ (1)
Summary Of Significant Accounting Policies
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.

 

  •  

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

 

  •  

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

 

  •  

AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company. Genco operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI, which it consolidates for financial reporting purposes.

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

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

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

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that affected Genco's three months ended March 31, 2011, consolidated statements of cash flows. For the three months ended March 31, 2011, Genco's previously reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected herein, 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. This correction had no impact on Ameren's 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 ended March 31, 2012, and 2011. In the first quarter of 2012, potential issuances of common shares related to stock-based compensation plans were excluded from the quarterly diluted earnings per share calculation because the effect was antidilutive. In 2011, the number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

 

Stock-based Compensation

A summary of nonvested shares as of March 31, 2012, and changes during the three months ended March 31, 2012, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units  
      Share Units    

Weighted-average Fair Value
Per Unit

at Grant Date

  

Nonvested at January 1, 2012

      1,156,831      $ 31.70   

Granted(a)

      717,151        35.68   

Forfeitures

      (3,897 )      32.94   

Vested(b)

      (110,729 )      35.68   

Nonvested at March 31, 2012

      1,759,356      $ 33.07   

 

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b) Share units vested due to 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 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren's closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $6 million and a related tax benefit of $2 million for both the three months ended March 31, 2012, and 2011. There were no significant compensation costs capitalized related to the performance share units during the three months ended March 31, 2012, and 2011. As of March 31, 2012, total compensation cost of $32 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 26 months.

Accounting Changes

Disclosures about Fair Value Measurements

In May 2011, FASB issued additional 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 do not affect the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2012. See Note 7 - Fair Value Measurements for the required additional disclosures.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changes the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies' results of operations, financial positions, or liquidity. In December 2011, the FASB amended the guidance to postpone a requirement to present reclassification adjustments by income component until further guidance is issued.

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 March 31, 2012, Ameren's and Ameren Illinois' goodwill related to Ameren's acquisition of IP in 2004 and 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.

 

At March 31, 2012, Ameren's and Ameren Missouri's intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits was $9 million at March 31, 2012. The book value of each of Ameren's, Ameren Missouri's, and Genco's CAIR emission allowances was immaterial at March 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. The amortization expense based on usage of renewable energy credits and emission allowances was less than $1 million for Ameren, Ameren Missouri, Ameren Illinois, and Genco for the three months ended March 31, 2012, and $2 million, $1 million, and $1 million for Ameren, Ameren Illinois, and Genco, respectively, for the three months ended March 31, 2011. Amortization expense based on Ameren Missouri's usage of renewable energy credits was deferred as a regulatory asset pending recovery from customers through rates.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in "Taxes accrued" on the balance sheet. The following table presents excise taxes recorded in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" for the three months ended March 31, 2012, and 2011:

 

XXXXXX XXXXXX
      Three Months  
      2012      2011  

Ameren Missouri

    $ 27       $ 29   

Ameren Illinois

      18         22   

Ameren

    $ 45       $ 51   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2012, was $150 million, $125 million, $11 million, and $10 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2012, that would impact the effective tax rate, if recognized, was $1 million, $1 million, $(1) million and $1 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. Ameren's federal income tax return for the year 2010 is currently under examination. In April 2012, Ameren filed a protest to the Appeals Office of the Internal Revenue Service with respect to certain adjustments proposed as a result of the Internal Revenue Service's audit examination of its 2010 federal income tax return.

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 expected that a partial settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2009 that would result in a decrease in uncertain tax liabilities. In addition, it is reasonably possible that events will occur during the next twelve 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, 2011, to reflect the accretion of obligations to their fair values. In addition, Ameren and Genco recorded an additional ARO in the amount of $1 million related to the retirement costs for a Genco coal combustion byproduct storage area during the three months ended March 31, 2012.

Noncontrolling Interest

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity 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 interest at Ameren and Genco for the three months ended March 31, 2012, and 2011, is shown below:

 

XXXXXXX XXXXXXX
      Three Months  
      2012     2011  

Ameren:

     

Noncontrolling interest, beginning of period

    $ 149      $ 154   

Net income attributable to noncontrolling interest

      -        3   

Dividends paid to noncontrolling interest holders

      (2 )      (2 ) 

Noncontrolling interest, end of period

    $ 147      $ 155   

Genco:

     

Noncontrolling interest, beginning of period

    $ 7      $ 11   

Net income (loss) attributable to noncontrolling interest

      (2 )      1   

Noncontrolling interest, end of period

    $ 5      $ 12   

Medina Valley Sale in 2012

In February 2012, Ameren completed the sale of its Medina Valley energy center's net property and plant for cash proceeds of $16 million and an additional $1 million payment at the two-year anniversary date of the sale if there are no violations of representations and warranties contained in the sale agreement. Ameren recognized a $10 million pretax gain during the first quarter of 2012 from this sale. Medina Valley was included in Ameren's Merchant Generation segment results.

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.

 

  •  

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

 

  •  

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

 

  •  

AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company. Genco operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI, which it consolidates for financial reporting purposes.

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

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

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

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that affected Genco's three months ended March 31, 2011, consolidated statements of cash flows. For the three months ended March 31, 2011, Genco's previously reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected herein, 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. This correction had no impact on Ameren's 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 ended March 31, 2012, and 2011. In the first quarter of 2012, potential issuances of common shares related to stock-based compensation plans were excluded from the quarterly diluted earnings per share calculation because the effect was antidilutive. In 2011, the number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

 

Stock-based Compensation

A summary of nonvested shares as of March 31, 2012, and changes during the three months ended March 31, 2012, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units  
      Share Units    

Weighted-average Fair Value
Per Unit

at Grant Date

  

Nonvested at January 1, 2012

      1,156,831      $ 31.70   

Granted(a)

      717,151        35.68   

Forfeitures

      (3,897 )      32.94   

Vested(b)

      (110,729 )      35.68   

Nonvested at March 31, 2012

      1,759,356      $ 33.07   

 

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b) Share units vested due to 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 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren's closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $6 million and a related tax benefit of $2 million for both the three months ended March 31, 2012, and 2011. There were no significant compensation costs capitalized related to the performance share units during the three months ended March 31, 2012, and 2011. As of March 31, 2012, total compensation cost of $32 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 26 months.

Accounting Changes

Disclosures about Fair Value Measurements

In May 2011, FASB issued additional 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 do not affect the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2012. See Note 7 - Fair Value Measurements for the required additional disclosures.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changes the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies' results of operations, financial positions, or liquidity. In December 2011, the FASB amended the guidance to postpone a requirement to present reclassification adjustments by income component until further guidance is issued.

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 March 31, 2012, Ameren's and Ameren Illinois' goodwill related to Ameren's acquisition of IP in 2004 and 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.

 

At March 31, 2012, Ameren's and Ameren Missouri's intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits was $9 million at March 31, 2012. The book value of each of Ameren's, Ameren Missouri's, and Genco's CAIR emission allowances was immaterial at March 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. The amortization expense based on usage of renewable energy credits and emission allowances was less than $1 million for Ameren, Ameren Missouri, Ameren Illinois, and Genco for the three months ended March 31, 2012, and $2 million, $1 million, and $1 million for Ameren, Ameren Illinois, and Genco, respectively, for the three months ended March 31, 2011. Amortization expense based on Ameren Missouri's usage of renewable energy credits was deferred as a regulatory asset pending recovery from customers through rates.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in "Taxes accrued" on the balance sheet. The following table presents excise taxes recorded in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" for the three months ended March 31, 2012, and 2011:

 

XXXXXX XXXXXX
      Three Months  
      2012      2011  

Ameren Missouri

    $ 27       $ 29   

Ameren Illinois

      18         22   

Ameren

    $ 45       $ 51   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2012, was $150 million, $125 million, $11 million, and $10 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2012, that would impact the effective tax rate, if recognized, was $1 million, $1 million, $(1) million and $1 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. Ameren's federal income tax return for the year 2010 is currently under examination. In April 2012, Ameren filed a protest to the Appeals Office of the Internal Revenue Service with respect to certain adjustments proposed as a result of the Internal Revenue Service's audit examination of its 2010 federal income tax return.

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 expected that a partial settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2009 that would result in a decrease in uncertain tax liabilities. In addition, it is reasonably possible that events will occur during the next twelve 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, 2011, to reflect the accretion of obligations to their fair values. In addition, Ameren and Genco recorded an additional ARO in the amount of $1 million related to the retirement costs for a Genco coal combustion byproduct storage area during the three months ended March 31, 2012.

Noncontrolling Interest

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity 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 interest at Ameren and Genco for the three months ended March 31, 2012, and 2011, is shown below:

 

XXXXXXX XXXXXXX
      Three Months  
      2012     2011  

Ameren:

     

Noncontrolling interest, beginning of period

    $ 149      $ 154   

Net income attributable to noncontrolling interest

      -        3   

Dividends paid to noncontrolling interest holders

      (2 )      (2 ) 

Noncontrolling interest, end of period

    $ 147      $ 155   

Genco:

     

Noncontrolling interest, beginning of period

    $ 7      $ 11   

Net income (loss) attributable to noncontrolling interest

      (2 )      1   

Noncontrolling interest, end of period

    $ 5      $ 12   

Medina Valley Sale in 2012

In February 2012, Ameren completed the sale of its Medina Valley energy center's net property and plant for cash proceeds of $16 million and an additional $1 million payment at the two-year anniversary date of the sale if there are no violations of representations and warranties contained in the sale agreement. Ameren recognized a $10 million pretax gain during the first quarter of 2012 from this sale. Medina Valley was included in Ameren's Merchant Generation segment results.

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.

 

  •  

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

 

  •  

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

 

  •  

AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company. Genco operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI, which it consolidates for financial reporting purposes.

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

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

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

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that affected Genco's three months ended March 31, 2011, consolidated statements of cash flows. For the three months ended March 31, 2011, Genco's previously reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected herein, 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. This correction had no impact on Ameren's 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 ended March 31, 2012, and 2011. In the first quarter of 2012, potential issuances of common shares related to stock-based compensation plans were excluded from the quarterly diluted earnings per share calculation because the effect was antidilutive. In 2011, the number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

 

Stock-based Compensation

A summary of nonvested shares as of March 31, 2012, and changes during the three months ended March 31, 2012, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units  
      Share Units    

Weighted-average Fair Value
Per Unit

at Grant Date

  

Nonvested at January 1, 2012

      1,156,831      $ 31.70   

Granted(a)

      717,151        35.68   

Forfeitures

      (3,897 )      32.94   

Vested(b)

      (110,729 )      35.68   

Nonvested at March 31, 2012

      1,759,356      $ 33.07   

 

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b) Share units vested due to 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 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren's closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $6 million and a related tax benefit of $2 million for both the three months ended March 31, 2012, and 2011. There were no significant compensation costs capitalized related to the performance share units during the three months ended March 31, 2012, and 2011. As of March 31, 2012, total compensation cost of $32 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 26 months.

Accounting Changes

Disclosures about Fair Value Measurements

In May 2011, FASB issued additional 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 do not affect the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2012. See Note 7 - Fair Value Measurements for the required additional disclosures.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changes the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies' results of operations, financial positions, or liquidity. In December 2011, the FASB amended the guidance to postpone a requirement to present reclassification adjustments by income component until further guidance is issued.

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 March 31, 2012, Ameren's and Ameren Illinois' goodwill related to Ameren's acquisition of IP in 2004 and 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.

 

At March 31, 2012, Ameren's and Ameren Missouri's intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits was $9 million at March 31, 2012. The book value of each of Ameren's, Ameren Missouri's, and Genco's CAIR emission allowances was immaterial at March 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. The amortization expense based on usage of renewable energy credits and emission allowances was less than $1 million for Ameren, Ameren Missouri, Ameren Illinois, and Genco for the three months ended March 31, 2012, and $2 million, $1 million, and $1 million for Ameren, Ameren Illinois, and Genco, respectively, for the three months ended March 31, 2011. Amortization expense based on Ameren Missouri's usage of renewable energy credits was deferred as a regulatory asset pending recovery from customers through rates.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in "Taxes accrued" on the balance sheet. The following table presents excise taxes recorded in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" for the three months ended March 31, 2012, and 2011:

 

XXXXXX XXXXXX
      Three Months  
      2012      2011  

Ameren Missouri

    $ 27       $ 29   

Ameren Illinois

      18         22   

Ameren

    $ 45       $ 51   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2012, was $150 million, $125 million, $11 million, and $10 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2012, that would impact the effective tax rate, if recognized, was $1 million, $1 million, $(1) million and $1 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. Ameren's federal income tax return for the year 2010 is currently under examination. In April 2012, Ameren filed a protest to the Appeals Office of the Internal Revenue Service with respect to certain adjustments proposed as a result of the Internal Revenue Service's audit examination of its 2010 federal income tax return.

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 expected that a partial settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2009 that would result in a decrease in uncertain tax liabilities. In addition, it is reasonably possible that events will occur during the next twelve 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, 2011, to reflect the accretion of obligations to their fair values. In addition, Ameren and Genco recorded an additional ARO in the amount of $1 million related to the retirement costs for a Genco coal combustion byproduct storage area during the three months ended March 31, 2012.

Noncontrolling Interest

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity 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 interest at Ameren and Genco for the three months ended March 31, 2012, and 2011, is shown below:

 

XXXXXXX XXXXXXX
      Three Months  
      2012     2011  

Ameren:

     

Noncontrolling interest, beginning of period

    $ 149      $ 154   

Net income attributable to noncontrolling interest

      -        3   

Dividends paid to noncontrolling interest holders

      (2 )      (2 ) 

Noncontrolling interest, end of period

    $ 147      $ 155   

Genco:

     

Noncontrolling interest, beginning of period

    $ 7      $ 11   

Net income (loss) attributable to noncontrolling interest

      (2 )      1   

Noncontrolling interest, end of period

    $ 5      $ 12   

Medina Valley Sale in 2012

In February 2012, Ameren completed the sale of its Medina Valley energy center's net property and plant for cash proceeds of $16 million and an additional $1 million payment at the two-year anniversary date of the sale if there are no violations of representations and warranties contained in the sale agreement. Ameren recognized a $10 million pretax gain during the first quarter of 2012 from this sale. Medina Valley was included in Ameren's Merchant Generation segment results.

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.

 

  •  

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

 

  •  

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

 

  •  

AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company. Genco operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI, which it consolidates for financial reporting purposes.

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

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

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

During the second quarter 2011, Genco identified an error in the cash flow statement classification of a capital contribution from Ameren that affected Genco's three months ended March 31, 2011, consolidated statements of cash flows. For the three months ended March 31, 2011, Genco's previously reported cash flows provided by operating activities were $100 million, and Genco had no reported cash flows from financing activities. As corrected herein, 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. This correction had no impact on Ameren's 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 ended March 31, 2012, and 2011. In the first quarter of 2012, potential issuances of common shares related to stock-based compensation plans were excluded from the quarterly diluted earnings per share calculation because the effect was antidilutive. In 2011, the number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

 

Stock-based Compensation

A summary of nonvested shares as of March 31, 2012, and changes during the three months ended March 31, 2012, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units  
      Share Units    

Weighted-average Fair Value
Per Unit

at Grant Date

  

Nonvested at January 1, 2012

      1,156,831      $ 31.70   

Granted(a)

      717,151        35.68   

Forfeitures

      (3,897 )      32.94   

Vested(b)

      (110,729 )      35.68   

Nonvested at March 31, 2012

      1,759,356      $ 33.07   

 

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b) Share units vested due to 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 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren's closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $6 million and a related tax benefit of $2 million for both the three months ended March 31, 2012, and 2011. There were no significant compensation costs capitalized related to the performance share units during the three months ended March 31, 2012, and 2011. As of March 31, 2012, total compensation cost of $32 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 26 months.

Accounting Changes

Disclosures about Fair Value Measurements

In May 2011, FASB issued additional 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 do not affect the Ameren Companies' results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. The Ameren Companies adopted this guidance for the first quarter of 2012. See Note 7 - Fair Value Measurements for the required additional disclosures.

Presentation of Comprehensive Income

In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changes the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies' results of operations, financial positions, or liquidity. In December 2011, the FASB amended the guidance to postpone a requirement to present reclassification adjustments by income component until further guidance is issued.

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 March 31, 2012, Ameren's and Ameren Illinois' goodwill related to Ameren's acquisition of IP in 2004 and 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.

 

At March 31, 2012, Ameren's and Ameren Missouri's intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits was $9 million at March 31, 2012. The book value of each of Ameren's, Ameren Missouri's, and Genco's CAIR emission allowances was immaterial at March 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. The amortization expense based on usage of renewable energy credits and emission allowances was less than $1 million for Ameren, Ameren Missouri, Ameren Illinois, and Genco for the three months ended March 31, 2012, and $2 million, $1 million, and $1 million for Ameren, Ameren Illinois, and Genco, respectively, for the three months ended March 31, 2011. Amortization expense based on Ameren Missouri's usage of renewable energy credits was deferred as a regulatory asset pending recovery from customers through rates.

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in "Taxes accrued" on the balance sheet. The following table presents excise taxes recorded in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" for the three months ended March 31, 2012, and 2011:

 

XXXXXX XXXXXX
      Three Months  
      2012      2011  

Ameren Missouri

    $ 27       $ 29   

Ameren Illinois

      18         22   

Ameren

    $ 45       $ 51   

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2012, was $150 million, $125 million, $11 million, and $10 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2012, that would impact the effective tax rate, if recognized, was $1 million, $1 million, $(1) million and $1 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. Ameren's federal income tax return for the year 2010 is currently under examination. In April 2012, Ameren filed a protest to the Appeals Office of the Internal Revenue Service with respect to certain adjustments proposed as a result of the Internal Revenue Service's audit examination of its 2010 federal income tax return.

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 expected that a partial settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2009 that would result in a decrease in uncertain tax liabilities. In addition, it is reasonably possible that events will occur during the next twelve 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, 2011, to reflect the accretion of obligations to their fair values. In addition, Ameren and Genco recorded an additional ARO in the amount of $1 million related to the retirement costs for a Genco coal combustion byproduct storage area during the three months ended March 31, 2012.

Noncontrolling Interest

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity 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 interest at Ameren and Genco for the three months ended March 31, 2012, and 2011, is shown below:

 

XXXXXXX XXXXXXX
      Three Months  
      2012     2011  

Ameren:

     

Noncontrolling interest, beginning of period

    $ 149      $ 154   

Net income attributable to noncontrolling interest

      -        3   

Dividends paid to noncontrolling interest holders

      (2 )      (2 ) 

Noncontrolling interest, end of period

    $ 147      $ 155   

Genco:

     

Noncontrolling interest, beginning of period

    $ 7      $ 11   

Net income (loss) attributable to noncontrolling interest

      (2 )      1   

Noncontrolling interest, end of period

    $ 5      $ 12   

Medina Valley Sale in 2012

In February 2012, Ameren completed the sale of its Medina Valley energy center's net property and plant for cash proceeds of $16 million and an additional $1 million payment at the two-year anniversary date of the sale if there are no violations of representations and warranties contained in the sale agreement. Ameren recognized a $10 million pretax gain during the first quarter of 2012 from this sale. Medina Valley was included in Ameren's Merchant Generation segment results.

Rate And Regulatory Matters
Rate And Regulatory Matters 

NOTE 2 - RATE AND REGULATORY MATTERS

Below is a summary of significant regulatory proceedings and related lawsuits. See also Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC's January 2009 electric rate order. In March 2012, the Circuit Court of Stoddard County, Missouri released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21 million, reducing previously recorded trade accounts receivable.

2010 Electric Rate Order

The MIEC and MoOPC appealed certain aspects of the MoPSC's electric rate order issued in May 2010 to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also were granted a stay by the Cole County Circuit Court of the 2010 electric rate increase and the 2009 electric rate increase that was also under appeal as it applied specifically to their electric service accounts until the court rendered its decision on the appeals. As of March 31, 2012, the amount held by the Cole County Circuit Court registry relating to the stay was $16 million. This amount was reflected in "Accounts receivable-trade" on Ameren's and Ameren Missouri's balance sheets at March 31, 2012. With the resolution of the 2009 electric rate order appeal, the amount held by the Cole County Circuit Court exceeded the amount relating to the appealed issues of the MoPSC's 2010 electric rate order. Therefore, in May 2012, Ameren Missouri received $14 million from the Cole Country Circuit Court's registry. The remaining $2 million in the Cole County Circuit Court's registry will stay until this proceeding is ultimately resolved.

If the MoPSC's 2010 electric rate order is ultimately upheld, Ameren Missouri will receive all of the remaining funds held in the Cole County Circuit Court's registry, plus accrued interest. If Ameren Missouri were to conclude that some portion of the rate increase resulting from the 2010 electric rate order was 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. At this time, Ameren Missouri does not believe any aspect of the 2010 MoPSC's electric rate order is probable of refund to Ameren Missouri's customers. Therefore, no reserve has been established.

2011 Electric Rate Order

In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million. 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.

In August 2011, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. A decision is expected by the Missouri Court of Appeals, Western District, in 2012. Ameren Missouri cannot predict the ultimate outcome of its appeal.

 

Pending Electric Rate Case

On February 3, 2012, Ameren Missouri filed a request with the MoPSC to increase its annual revenue for electric service by $376 million. The annual increase request included $81 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. As part of its filing, Ameren Missouri requested that the MoPSC approve the implementation of a storm cost tracking mechanism, as well as plant-in-service accounting treatment.

A decision by the MoPSC in this proceeding is expected in December 2012. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

MEEIA Filing

In January 2012, Ameren Missouri made its initial filing with the MoPSC under the MEEIA. This filing proposed a three-year plan that includes a portfolio of energy efficiency programs along with a cost-recovery mechanism. If the proposal is approved, beginning in January 2013, Ameren Missouri plans to invest $145 million over three years for the proposed energy efficiency programs. Ameren Missouri is also seeking recovery of fixed costs that would not otherwise be recovered due to the effects on customer usage from energy efficiency programs in the same year the usage reduction occurs.

In April 2012, the MoPSC staff issued a recommendation in response to Ameren Missouri's MEEIA filing. The MoPSC staff agreed with Ameren Missouri's request for contemporaneous recovery of program costs but rejected Ameren Missouri's request to recover fixed costs in the same year the energy efficiency related usage reductions occur. Instead, the MoPSC staff recommended that the recovery of the otherwise unrecoverable fixed costs occur beginning on January 1 of the third year after the usage reduction occurs and has been verified by an independent evaluator.

A decision by the MoPSC in this proceeding is anticipated in the third quarter of 2012. The MoPSC's order in this proceeding will not affect Ameren Missouri rates until these rates are included in an electric service rate case. Ameren Missouri anticipates that the impacts of the MoPSC's decision in this MEEIA filing will be included in rates set under its pending electric service rate case that was filed on February 3, 2012, with a true-up date of July 31, 2012. Ameren Missouri's pending electric rate case includes an annual revenue increase of $81 million related to its planned portfolio of energy efficiency programs included in its MEEIA filing.

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 review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009. Ameren Missouri expects to have refunded the $18 million by the end of May 2012.

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 June 2011, Ameren Missouri filed an appeal with the Cole County Circuit Court. A decision is expected from the Cole County Circuit Court in 2012. 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.

In February 2012, the MoPSC staff issued its FAC review report for the period from October 1, 2009, to May 31, 2011. In its report, the MoPSC staff's position directed Ameren Missouri to refund to customers the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. We cannot predict whether the MoPSC will approve the MoPSC staff's position. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probable of refund to customers.

 

Illinois

IEIMA

On January 3, 2012, Ameren Illinois elected to participate in the performance-based formula ratemaking process established pursuant to the IEIMA by filing initial performance-based formula rates with the ICC. The initial filing, based on 2010 recoverable costs and expected net plant additions for 2011 and 2012, will result in new electric delivery service rates in October 2012. In its initial filing, if approved by the ICC, Ameren Illinois' calculation would result in a decrease of $19 million in its annual electric delivery service revenues. In April 2012, the ICC staff submitted its calculation of Ameren Illinois' initial filing's revenue requirement and recommended a decrease of $25 million in Ameren Illinois' annual electric delivery service revenues. The ICC deadline to approve the initial formula rates is September 28, 2012, with the rates becoming effective no later than 30 days after the ICC's decision. The rates resulting from the initial filing will be effective from October through the end of 2012.

On April 20, 2012, Ameren Illinois filed a request with the ICC to update its electric delivery service revenue requirement based on 2011 recoverable costs and expected net plant additions for 2012. The update filing will result in new electric delivery service rates on January 1, 2013. Pending ICC approval, the update filing will result in an annual decrease of $15 million in Ameren Illinois' revenues for electric delivery service below the amount Ameren Illinois requested in its January 3, 2012 initial filing. The reduction primarily reflects rate base reductions due to increases in accumulated deferred income taxes, as well as a lower return on equity due to decreases in the average 30-year United States treasury bond rates.

The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year. Consequently, Ameren Illinois' 2012 electric delivery service revenues will be based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. As a result, throughout the year, Ameren Illinois will estimate the expected future recovery or return of revenue as a regulatory asset or liability. As of March 31, 2012, Ameren Illinois recorded a regulatory asset of $12 million with a corresponding increase in electric revenues for the estimated first quarter portion of the 2012 revenue requirement reconciliation adjustment. By the end of 2012, this regulatory asset will represent Ameren Illinois' estimate of the probable increase in electric delivery service rates, compared to current and proposed rates, expected to be approved by the ICC to provide Ameren Illinois recovery of all prudently and reasonably incurred costs in 2012 and an earned rate of return on common equity for 2012. The regulatory asset relating to the 2012 revenue requirement reconciliation will be recovered from customers during 2014.

Federal

Electric Transmission Investment

In February 2012, FERC approved ATXI's request for a forward-looking rate calculation with an annual reconciliation adjustment as well as ATXI's request for the implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project and the Big Muddy project.

2011 Wholesale Distribution Rate Case

In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers by $11 million. These wholesale distribution revenues are treated as a deduction from Ameren Illinois' revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois reached an agreement with two of its nine wholesale customers in 2011. The impasse with the remaining seven wholesale customers has resulted in FERC litigation. An initial decision by the FERC administrative law judge is expected in 2012, and a final FERC decision may be received after 2012. We cannot predict the ultimate outcome of this proceeding or its impact on Ameren's or Ameren Illinois' results of operations, financial position, or liquidity.

Regional Transmission Organization

Ameren Missouri is a transmission owning member of MISO. In April 2012, the MoPSC authorized Ameren Missouri's continued participation in MISO through May 31, 2016, subject to certain conditions. By November 2015, Ameren Missouri will have to file an updated cost benefit study with the MoPSC evaluating the costs and benefits of Ameren Missouri's continued participation in MISO.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL 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 COL application.

In March 2012, the DOE announced the availability of $452 million of investment funds for the design, engineering, manufacturing, and sale of American-made small modular reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the DOE's small modular reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. Westinghouse expects to submit its application to the DOE in May 2012. The DOE is expected to issue a decision on awarding the investment funds in the summer of 2012.

If Westinghouse is awarded DOE's small modular reactor investment funds, Ameren Missouri will seek a COL from the NRC for a Westinghouse small modular reactor at its Callaway County, Missouri nuclear energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear power plant at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC does not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it does preserve the option to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years.

Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL will be minimal due to several factors, including the company's capitalized investments of $69 million as of March 31, 2012, in new nuclear energy center development, the DOE investment funds that would help support the COL application, and its agreement with Westinghouse. If the DOE does not approve Westinghouse's application for the small modular reactor investment funds, Ameren Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse.

All of Ameren Missouri's costs incurred to construct a new nuclear unit will remain capitalized while management pursues 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. See also Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC's January 2009 electric rate order. In March 2012, the Circuit Court of Stoddard County, Missouri released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21 million, reducing previously recorded trade accounts receivable.

2010 Electric Rate Order

The MIEC and MoOPC appealed certain aspects of the MoPSC's electric rate order issued in May 2010 to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also were granted a stay by the Cole County Circuit Court of the 2010 electric rate increase and the 2009 electric rate increase that was also under appeal as it applied specifically to their electric service accounts until the court rendered its decision on the appeals. As of March 31, 2012, the amount held by the Cole County Circuit Court registry relating to the stay was $16 million. This amount was reflected in "Accounts receivable-trade" on Ameren's and Ameren Missouri's balance sheets at March 31, 2012. With the resolution of the 2009 electric rate order appeal, the amount held by the Cole County Circuit Court exceeded the amount relating to the appealed issues of the MoPSC's 2010 electric rate order. Therefore, in May 2012, Ameren Missouri received $14 million from the Cole Country Circuit Court's registry. The remaining $2 million in the Cole County Circuit Court's registry will stay until this proceeding is ultimately resolved.

If the MoPSC's 2010 electric rate order is ultimately upheld, Ameren Missouri will receive all of the remaining funds held in the Cole County Circuit Court's registry, plus accrued interest. If Ameren Missouri were to conclude that some portion of the rate increase resulting from the 2010 electric rate order was 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. At this time, Ameren Missouri does not believe any aspect of the 2010 MoPSC's electric rate order is probable of refund to Ameren Missouri's customers. Therefore, no reserve has been established.

2011 Electric Rate Order

In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million. 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.

In August 2011, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. A decision is expected by the Missouri Court of Appeals, Western District, in 2012. Ameren Missouri cannot predict the ultimate outcome of its appeal.

 

Pending Electric Rate Case

On February 3, 2012, Ameren Missouri filed a request with the MoPSC to increase its annual revenue for electric service by $376 million. The annual increase request included $81 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. As part of its filing, Ameren Missouri requested that the MoPSC approve the implementation of a storm cost tracking mechanism, as well as plant-in-service accounting treatment.

A decision by the MoPSC in this proceeding is expected in December 2012. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

MEEIA Filing

In January 2012, Ameren Missouri made its initial filing with the MoPSC under the MEEIA. This filing proposed a three-year plan that includes a portfolio of energy efficiency programs along with a cost-recovery mechanism. If the proposal is approved, beginning in January 2013, Ameren Missouri plans to invest $145 million over three years for the proposed energy efficiency programs. Ameren Missouri is also seeking recovery of fixed costs that would not otherwise be recovered due to the effects on customer usage from energy efficiency programs in the same year the usage reduction occurs.

In April 2012, the MoPSC staff issued a recommendation in response to Ameren Missouri's MEEIA filing. The MoPSC staff agreed with Ameren Missouri's request for contemporaneous recovery of program costs but rejected Ameren Missouri's request to recover fixed costs in the same year the energy efficiency related usage reductions occur. Instead, the MoPSC staff recommended that the recovery of the otherwise unrecoverable fixed costs occur beginning on January 1 of the third year after the usage reduction occurs and has been verified by an independent evaluator.

A decision by the MoPSC in this proceeding is anticipated in the third quarter of 2012. The MoPSC's order in this proceeding will not affect Ameren Missouri rates until these rates are included in an electric service rate case. Ameren Missouri anticipates that the impacts of the MoPSC's decision in this MEEIA filing will be included in rates set under its pending electric service rate case that was filed on February 3, 2012, with a true-up date of July 31, 2012. Ameren Missouri's pending electric rate case includes an annual revenue increase of $81 million related to its planned portfolio of energy efficiency programs included in its MEEIA filing.

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 review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009. Ameren Missouri expects to have refunded the $18 million by the end of May 2012.

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 June 2011, Ameren Missouri filed an appeal with the Cole County Circuit Court. A decision is expected from the Cole County Circuit Court in 2012. 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.

In February 2012, the MoPSC staff issued its FAC review report for the period from October 1, 2009, to May 31, 2011. In its report, the MoPSC staff's position directed Ameren Missouri to refund to customers the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. We cannot predict whether the MoPSC will approve the MoPSC staff's position. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probable of refund to customers.

 

Illinois

IEIMA

On January 3, 2012, Ameren Illinois elected to participate in the performance-based formula ratemaking process established pursuant to the IEIMA by filing initial performance-based formula rates with the ICC. The initial filing, based on 2010 recoverable costs and expected net plant additions for 2011 and 2012, will result in new electric delivery service rates in October 2012. In its initial filing, if approved by the ICC, Ameren Illinois' calculation would result in a decrease of $19 million in its annual electric delivery service revenues. In April 2012, the ICC staff submitted its calculation of Ameren Illinois' initial filing's revenue requirement and recommended a decrease of $25 million in Ameren Illinois' annual electric delivery service revenues. The ICC deadline to approve the initial formula rates is September 28, 2012, with the rates becoming effective no later than 30 days after the ICC's decision. The rates resulting from the initial filing will be effective from October through the end of 2012.

On April 20, 2012, Ameren Illinois filed a request with the ICC to update its electric delivery service revenue requirement based on 2011 recoverable costs and expected net plant additions for 2012. The update filing will result in new electric delivery service rates on January 1, 2013. Pending ICC approval, the update filing will result in an annual decrease of $15 million in Ameren Illinois' revenues for electric delivery service below the amount Ameren Illinois requested in its January 3, 2012 initial filing. The reduction primarily reflects rate base reductions due to increases in accumulated deferred income taxes, as well as a lower return on equity due to decreases in the average 30-year United States treasury bond rates.

The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year. Consequently, Ameren Illinois' 2012 electric delivery service revenues will be based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. As a result, throughout the year, Ameren Illinois will estimate the expected future recovery or return of revenue as a regulatory asset or liability. As of March 31, 2012, Ameren Illinois recorded a regulatory asset of $12 million with a corresponding increase in electric revenues for the estimated first quarter portion of the 2012 revenue requirement reconciliation adjustment. By the end of 2012, this regulatory asset will represent Ameren Illinois' estimate of the probable increase in electric delivery service rates, compared to current and proposed rates, expected to be approved by the ICC to provide Ameren Illinois recovery of all prudently and reasonably incurred costs in 2012 and an earned rate of return on common equity for 2012. The regulatory asset relating to the 2012 revenue requirement reconciliation will be recovered from customers during 2014.

Federal

Electric Transmission Investment

In February 2012, FERC approved ATXI's request for a forward-looking rate calculation with an annual reconciliation adjustment as well as ATXI's request for the implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project and the Big Muddy project.

2011 Wholesale Distribution Rate Case

In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers by $11 million. These wholesale distribution revenues are treated as a deduction from Ameren Illinois' revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois reached an agreement with two of its nine wholesale customers in 2011. The impasse with the remaining seven wholesale customers has resulted in FERC litigation. An initial decision by the FERC administrative law judge is expected in 2012, and a final FERC decision may be received after 2012. We cannot predict the ultimate outcome of this proceeding or its impact on Ameren's or Ameren Illinois' results of operations, financial position, or liquidity.

Regional Transmission Organization

Ameren Missouri is a transmission owning member of MISO. In April 2012, the MoPSC authorized Ameren Missouri's continued participation in MISO through May 31, 2016, subject to certain conditions. By November 2015, Ameren Missouri will have to file an updated cost benefit study with the MoPSC evaluating the costs and benefits of Ameren Missouri's continued participation in MISO.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL 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 COL application.

In March 2012, the DOE announced the availability of $452 million of investment funds for the design, engineering, manufacturing, and sale of American-made small modular reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the DOE's small modular reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. Westinghouse expects to submit its application to the DOE in May 2012. The DOE is expected to issue a decision on awarding the investment funds in the summer of 2012.

If Westinghouse is awarded DOE's small modular reactor investment funds, Ameren Missouri will seek a COL from the NRC for a Westinghouse small modular reactor at its Callaway County, Missouri nuclear energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear power plant at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC does not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it does preserve the option to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years.

Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL will be minimal due to several factors, including the company's capitalized investments of $69 million as of March 31, 2012, in new nuclear energy center development, the DOE investment funds that would help support the COL application, and its agreement with Westinghouse. If the DOE does not approve Westinghouse's application for the small modular reactor investment funds, Ameren Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse.

All of Ameren Missouri's costs incurred to construct a new nuclear unit will remain capitalized while management pursues 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. See also Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity.

Missouri

2009 Electric Rate Order

In November 2011, the Missouri Court of Appeals issued a ruling that upheld the MoPSC's January 2009 electric rate order. In March 2012, the Circuit Court of Stoddard County, Missouri released to Ameren Missouri all of the funds held in its registry relating to the stay, which totaled $21 million, reducing previously recorded trade accounts receivable.

2010 Electric Rate Order

The MIEC and MoOPC appealed certain aspects of the MoPSC's electric rate order issued in May 2010 to the Cole County Circuit Court. In addition to the MIEC appeal, four industrial customers, who are members of MIEC, also were granted a stay by the Cole County Circuit Court of the 2010 electric rate increase and the 2009 electric rate increase that was also under appeal as it applied specifically to their electric service accounts until the court rendered its decision on the appeals. As of March 31, 2012, the amount held by the Cole County Circuit Court registry relating to the stay was $16 million. This amount was reflected in "Accounts receivable-trade" on Ameren's and Ameren Missouri's balance sheets at March 31, 2012. With the resolution of the 2009 electric rate order appeal, the amount held by the Cole County Circuit Court exceeded the amount relating to the appealed issues of the MoPSC's 2010 electric rate order. Therefore, in May 2012, Ameren Missouri received $14 million from the Cole Country Circuit Court's registry. The remaining $2 million in the Cole County Circuit Court's registry will stay until this proceeding is ultimately resolved.

If the MoPSC's 2010 electric rate order is ultimately upheld, Ameren Missouri will receive all of the remaining funds held in the Cole County Circuit Court's registry, plus accrued interest. If Ameren Missouri were to conclude that some portion of the rate increase resulting from the 2010 electric rate order was 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. At this time, Ameren Missouri does not believe any aspect of the 2010 MoPSC's electric rate order is probable of refund to Ameren Missouri's customers. Therefore, no reserve has been established.

2011 Electric Rate Order

In July 2011, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $173 million. 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.

In August 2011, Ameren Missouri appealed the disallowance of Taum Sauk enhancements to the Missouri Court of Appeals, Western District. A decision is expected by the Missouri Court of Appeals, Western District, in 2012. Ameren Missouri cannot predict the ultimate outcome of its appeal.

 

Pending Electric Rate Case

On February 3, 2012, Ameren Missouri filed a request with the MoPSC to increase its annual revenue for electric service by $376 million. The annual increase request included $81 million for recovery of the costs associated with energy efficiency programs under the MEEIA, which are discussed below. As part of its filing, Ameren Missouri requested that the MoPSC approve the implementation of a storm cost tracking mechanism, as well as plant-in-service accounting treatment.

A decision by the MoPSC in this proceeding is expected in December 2012. Ameren Missouri cannot predict the level of any electric service rate change the MoPSC may approve, when any rate change may go into effect, or whether any rate increase that may eventually be approved will be sufficient for Ameren Missouri to recover its costs and earn a reasonable return on its investments when the increase goes into effect.

MEEIA Filing

In January 2012, Ameren Missouri made its initial filing with the MoPSC under the MEEIA. This filing proposed a three-year plan that includes a portfolio of energy efficiency programs along with a cost-recovery mechanism. If the proposal is approved, beginning in January 2013, Ameren Missouri plans to invest $145 million over three years for the proposed energy efficiency programs. Ameren Missouri is also seeking recovery of fixed costs that would not otherwise be recovered due to the effects on customer usage from energy efficiency programs in the same year the usage reduction occurs.

In April 2012, the MoPSC staff issued a recommendation in response to Ameren Missouri's MEEIA filing. The MoPSC staff agreed with Ameren Missouri's request for contemporaneous recovery of program costs but rejected Ameren Missouri's request to recover fixed costs in the same year the energy efficiency related usage reductions occur. Instead, the MoPSC staff recommended that the recovery of the otherwise unrecoverable fixed costs occur beginning on January 1 of the third year after the usage reduction occurs and has been verified by an independent evaluator.

A decision by the MoPSC in this proceeding is anticipated in the third quarter of 2012. The MoPSC's order in this proceeding will not affect Ameren Missouri rates until these rates are included in an electric service rate case. Ameren Missouri anticipates that the impacts of the MoPSC's decision in this MEEIA filing will be included in rates set under its pending electric service rate case that was filed on February 3, 2012, with a true-up date of July 31, 2012. Ameren Missouri's pending electric rate case includes an annual revenue increase of $81 million related to its planned portfolio of energy efficiency programs included in its MEEIA filing.

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 review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009. Ameren Missouri expects to have refunded the $18 million by the end of May 2012.

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 June 2011, Ameren Missouri filed an appeal with the Cole County Circuit Court. A decision is expected from the Cole County Circuit Court in 2012. 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.

In February 2012, the MoPSC staff issued its FAC review report for the period from October 1, 2009, to May 31, 2011. In its report, the MoPSC staff's position directed Ameren Missouri to refund to customers the pretax earnings associated with the same long-term partial requirements sales contracts subsequent to September 30, 2009. The MoPSC staff calculated these pretax earnings to be $26 million. We cannot predict whether the MoPSC will approve the MoPSC staff's position. If Ameren Missouri were to determine that these sales were probable of refund to Ameren Missouri's electric customers, a charge to earnings would be recorded for the refund in the period in which that determination was made. Ameren Missouri does not currently believe these amounts are probable of refund to customers.

 

Illinois

IEIMA

On January 3, 2012, Ameren Illinois elected to participate in the performance-based formula ratemaking process established pursuant to the IEIMA by filing initial performance-based formula rates with the ICC. The initial filing, based on 2010 recoverable costs and expected net plant additions for 2011 and 2012, will result in new electric delivery service rates in October 2012. In its initial filing, if approved by the ICC, Ameren Illinois' calculation would result in a decrease of $19 million in its annual electric delivery service revenues. In April 2012, the ICC staff submitted its calculation of Ameren Illinois' initial filing's revenue requirement and recommended a decrease of $25 million in Ameren Illinois' annual electric delivery service revenues. The ICC deadline to approve the initial formula rates is September 28, 2012, with the rates becoming effective no later than 30 days after the ICC's decision. The rates resulting from the initial filing will be effective from October through the end of 2012.

On April 20, 2012, Ameren Illinois filed a request with the ICC to update its electric delivery service revenue requirement based on 2011 recoverable costs and expected net plant additions for 2012. The update filing will result in new electric delivery service rates on January 1, 2013. Pending ICC approval, the update filing will result in an annual decrease of $15 million in Ameren Illinois' revenues for electric delivery service below the amount Ameren Illinois requested in its January 3, 2012 initial filing. The reduction primarily reflects rate base reductions due to increases in accumulated deferred income taxes, as well as a lower return on equity due to decreases in the average 30-year United States treasury bond rates.

The IEIMA provides for an annual reconciliation of the revenue requirement necessary to reflect the actual costs incurred in a given year with the revenue requirement that was in effect for that year. Consequently, Ameren Illinois' 2012 electric delivery service revenues will be based on its 2012 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. As a result, throughout the year, Ameren Illinois will estimate the expected future recovery or return of revenue as a regulatory asset or liability. As of March 31, 2012, Ameren Illinois recorded a regulatory asset of $12 million with a corresponding increase in electric revenues for the estimated first quarter portion of the 2012 revenue requirement reconciliation adjustment. By the end of 2012, this regulatory asset will represent Ameren Illinois' estimate of the probable increase in electric delivery service rates, compared to current and proposed rates, expected to be approved by the ICC to provide Ameren Illinois recovery of all prudently and reasonably incurred costs in 2012 and an earned rate of return on common equity for 2012. The regulatory asset relating to the 2012 revenue requirement reconciliation will be recovered from customers during 2014.

Federal

Electric Transmission Investment

In February 2012, FERC approved ATXI's request for a forward-looking rate calculation with an annual reconciliation adjustment as well as ATXI's request for the implementation of the incentives FERC approved in its May 2011 order for the Illinois Rivers project and the Big Muddy project.

2011 Wholesale Distribution Rate Case

In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers by $11 million. These wholesale distribution revenues are treated as a deduction from Ameren Illinois' revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois reached an agreement with two of its nine wholesale customers in 2011. The impasse with the remaining seven wholesale customers has resulted in FERC litigation. An initial decision by the FERC administrative law judge is expected in 2012, and a final FERC decision may be received after 2012. We cannot predict the ultimate outcome of this proceeding or its impact on Ameren's or Ameren Illinois' results of operations, financial position, or liquidity.

Regional Transmission Organization

Ameren Missouri is a transmission owning member of MISO. In April 2012, the MoPSC authorized Ameren Missouri's continued participation in MISO through May 31, 2016, subject to certain conditions. By November 2015, Ameren Missouri will have to file an updated cost benefit study with the MoPSC evaluating the costs and benefits of Ameren Missouri's continued participation in MISO.

Combined Construction and Operating License

In 2008, Ameren Missouri filed an application with the NRC for a COL 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 COL application.

In March 2012, the DOE announced the availability of $452 million of investment funds for the design, engineering, manufacturing, and sale of American-made small modular reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the DOE's small modular reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. Westinghouse expects to submit its application to the DOE in May 2012. The DOE is expected to issue a decision on awarding the investment funds in the summer of 2012.

If Westinghouse is awarded DOE's small modular reactor investment funds, Ameren Missouri will seek a COL from the NRC for a Westinghouse small modular reactor at its Callaway County, Missouri nuclear energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear power plant at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC does not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it does preserve the option to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years.

Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL will be minimal due to several factors, including the company's capitalized investments of $69 million as of March 31, 2012, in new nuclear energy center development, the DOE investment funds that would help support the COL application, and its agreement with Westinghouse. If the DOE does not approve Westinghouse's application for the small modular reactor investment funds, Ameren Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse.

All of Ameren Missouri's costs incurred to construct a new nuclear unit will remain capitalized while management pursues 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.

Short-Term Debt And Liquidity
Short-Term Debt And Liquidity 

NOTE 3 - SHORT-TERM DEBT AND LIQUIDITY

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

Ameren, Ameren Missouri, Ameren Illinois and Genco had no borrowings under the 2010 Credit Agreements during the three months ended March 31, 2012. Based on letters of credit issued under the 2010 Credit Agreements as of March 31, 2012, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available at March 31, 2012, was $1.96 billion.

Commercial Paper

At March 31, 2012, and December 31, 2011, Ameren had $126 million and $148 million of commercial paper outstanding, respectively. During the three months ended March 31, 2012 and 2011, Ameren had average daily commercial paper balances outstanding of $84 million and $321 million, respectively, with a weighted-average interest rate of 0.94% for both periods. The peak short-term commercial paper balances outstanding during the three months ended March 31, 2012, and 2011 were $186 million and $377 million, respectively. The peak interest rates during the three months ended March 31, 2012, and 2011 were 1.25% and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants within the 2010 Credit Agreements. See Note 4—Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions about 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 obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 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 its 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 March 31, 2012, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 48%, 41% 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 March 31, 2012, was 5 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

None of the Ameren Companies' credit facilities or financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit facilities at March 31, 2012.

Money Pools

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

Utility

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren 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 participants, but increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2012, was 0.11%. There were no utility money pool borrowings during the three months ended March 31, 2011.

Non-state-regulated Subsidiaries

Ameren, Ameren Services, AER, 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. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2012, was 0.76% (2011—1.14%).

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 months ended March 31, 2012 and 2011.

Short-Term Debt And Liquidity 

NOTE 3 - SHORT-TERM DEBT AND LIQUIDITY

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

Ameren, Ameren Missouri, Ameren Illinois and Genco had no borrowings under the 2010 Credit Agreements during the three months ended March 31, 2012. Based on letters of credit issued under the 2010 Credit Agreements as of March 31, 2012, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available at March 31, 2012, was $1.96 billion.

Commercial Paper

At March 31, 2012, and December 31, 2011, Ameren had $126 million and $148 million of commercial paper outstanding, respectively. During the three months ended March 31, 2012 and 2011, Ameren had average daily commercial paper balances outstanding of $84 million and $321 million, respectively, with a weighted-average interest rate of 0.94% for both periods. The peak short-term commercial paper balances outstanding during the three months ended March 31, 2012, and 2011 were $186 million and $377 million, respectively. The peak interest rates during the three months ended March 31, 2012, and 2011 were 1.25% and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants within the 2010 Credit Agreements. See Note 4—Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions about 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 obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 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 its 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 March 31, 2012, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 48%, 41% 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 March 31, 2012, was 5 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

None of the Ameren Companies' credit facilities or financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit facilities at March 31, 2012.

Money Pools

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

Utility

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren 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 participants, but increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2012, was 0.11%. There were no utility money pool borrowings during the three months ended March 31, 2011.

Non-state-regulated Subsidiaries

Ameren, Ameren Services, AER, 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. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2012, was 0.76% (2011—1.14%).

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 months ended March 31, 2012 and 2011.

Short-Term Debt And Liquidity 

NOTE 3 - SHORT-TERM DEBT AND LIQUIDITY

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

Ameren, Ameren Missouri, Ameren Illinois and Genco had no borrowings under the 2010 Credit Agreements during the three months ended March 31, 2012. Based on letters of credit issued under the 2010 Credit Agreements as of March 31, 2012, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available at March 31, 2012, was $1.96 billion.

Commercial Paper

At March 31, 2012, and December 31, 2011, Ameren had $126 million and $148 million of commercial paper outstanding, respectively. During the three months ended March 31, 2012 and 2011, Ameren had average daily commercial paper balances outstanding of $84 million and $321 million, respectively, with a weighted-average interest rate of 0.94% for both periods. The peak short-term commercial paper balances outstanding during the three months ended March 31, 2012, and 2011 were $186 million and $377 million, respectively. The peak interest rates during the three months ended March 31, 2012, and 2011 were 1.25% and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants within the 2010 Credit Agreements. See Note 4—Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions about 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 obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 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 its 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 March 31, 2012, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 48%, 41% 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 March 31, 2012, was 5 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

None of the Ameren Companies' credit facilities or financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit facilities at March 31, 2012.

Money Pools

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

Utility

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren 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 participants, but increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2012, was 0.11%. There were no utility money pool borrowings during the three months ended March 31, 2011.

Non-state-regulated Subsidiaries

Ameren, Ameren Services, AER, 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. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2012, was 0.76% (2011—1.14%).

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 months ended March 31, 2012 and 2011.

Short-Term Debt And Liquidity 

NOTE 3 - SHORT-TERM DEBT AND LIQUIDITY

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

Ameren, Ameren Missouri, Ameren Illinois and Genco had no borrowings under the 2010 Credit Agreements during the three months ended March 31, 2012. Based on letters of credit issued under the 2010 Credit Agreements as of March 31, 2012, as well as commercial paper outstanding as of such date, the aggregate amount of credit capacity available at March 31, 2012, was $1.96 billion.

Commercial Paper

At March 31, 2012, and December 31, 2011, Ameren had $126 million and $148 million of commercial paper outstanding, respectively. During the three months ended March 31, 2012 and 2011, Ameren had average daily commercial paper balances outstanding of $84 million and $321 million, respectively, with a weighted-average interest rate of 0.94% for both periods. The peak short-term commercial paper balances outstanding during the three months ended March 31, 2012, and 2011 were $186 million and $377 million, respectively. The peak interest rates during the three months ended March 31, 2012, and 2011 were 1.25% and 1.46%, respectively.

Indebtedness Provisions and Other Covenants

The information below presents a summary of the Ameren Companies' compliance with indebtedness provisions and other covenants within the 2010 Credit Agreements. See Note 4—Credit Facility Borrowings and Liquidity in the Form 10-K for a detailed description of those provisions.

The 2010 Credit Agreements contain conditions about 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 obtaining required regulatory authorizations. In addition, solely as it relates to borrowings under the 2010 Illinois Credit Agreement, it is a condition for any such borrowing that, at the time of and after giving effect to such borrowing, the borrower not be in violation of any limitation on its ability to incur unsecured indebtedness contained in its articles of incorporation. The 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 its 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 March 31, 2012, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2010 Credit Agreements, were 49%, 48%, 41% 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 March 31, 2012, was 5 to 1. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2010 Credit Agreement.

None of the Ameren Companies' credit facilities or financing arrangements contains credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit facilities at March 31, 2012.

Money Pools

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

Utility

Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren 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 participants, but increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2012, was 0.11%. There were no utility money pool borrowings during the three months ended March 31, 2011.

Non-state-regulated Subsidiaries

Ameren, Ameren Services, AER, 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. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2012, was 0.76% (2011—1.14%).

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 months ended March 31, 2012 and 2011.

Long-Term Debt And Equity Financings
Long-Term Debt And Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, a failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies' ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable for the 12 months ended March 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.

 

      Required Interest
Coverage Ratio (a)		    Actual Interest
Coverage Ratio		      Bonds Issuable (b)     Required Dividend
Coverage Ratio(c)		    Actual Dividend
Coverage Ratio		      Preferred Stock
Issuable		  

Ameren Missouri

    ³2.0      3.2       $ 2,004      ³2.5      85.1       $ 1,614   

Ameren Illinois

    ³2.0      7.2         3,373 (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 $89 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 in the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 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, Genco and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Illinois' articles of incorporation require 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 after the Ameren Illinois Merger and AERG distribution. As of March 31, 2012, Ameren Illinois' ratio of common stock equity to total capitalization was 58%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third party indebtedness. The following table summarizes these ratios for the 12 months ended and as of March 31, 2012:

 

      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)     3.66       £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 payments and, principal and interest payments on subordinated 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. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
(b) 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, for borrowed money. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Credit facility borrowings, including borrowings under the 2010 Genco Credit Agreement, and other borrowings from third-party, external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

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

Off-Balance-Sheet Arrangements

At March 31, 2012, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

Long-Term Debt And Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, a failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies' ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable for the 12 months ended March 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.

 

      Required Interest
Coverage Ratio (a)		    Actual Interest
Coverage Ratio		      Bonds Issuable (b)     Required Dividend
Coverage Ratio(c)		    Actual Dividend
Coverage Ratio		      Preferred Stock
Issuable		  

Ameren Missouri

    ³2.0      3.2       $ 2,004      ³2.5      85.1       $ 1,614   

Ameren Illinois

    ³2.0      7.2         3,373 (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 $89 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 in the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 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, Genco and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Illinois' articles of incorporation require 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 after the Ameren Illinois Merger and AERG distribution. As of March 31, 2012, Ameren Illinois' ratio of common stock equity to total capitalization was 58%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third party indebtedness. The following table summarizes these ratios for the 12 months ended and as of March 31, 2012:

 

      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)     3.66       £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 payments and, principal and interest payments on subordinated 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. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
(b) 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, for borrowed money. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Credit facility borrowings, including borrowings under the 2010 Genco Credit Agreement, and other borrowings from third-party, external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

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

Off-Balance-Sheet Arrangements

At March 31, 2012, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

Long-Term Debt And Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, a failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies' ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable for the 12 months ended March 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.

 

      Required Interest
Coverage Ratio (a)		    Actual Interest
Coverage Ratio		      Bonds Issuable (b)     Required Dividend
Coverage Ratio(c)		    Actual Dividend
Coverage Ratio		      Preferred Stock
Issuable		  

Ameren Missouri

    ³2.0      3.2       $ 2,004      ³2.5      85.1       $ 1,614   

Ameren Illinois

    ³2.0      7.2         3,373 (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 $89 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 in the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 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, Genco and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Illinois' articles of incorporation require 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 after the Ameren Illinois Merger and AERG distribution. As of March 31, 2012, Ameren Illinois' ratio of common stock equity to total capitalization was 58%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third party indebtedness. The following table summarizes these ratios for the 12 months ended and as of March 31, 2012:

 

      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)     3.66       £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 payments and, principal and interest payments on subordinated 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. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
(b) 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, for borrowed money. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Credit facility borrowings, including borrowings under the 2010 Genco Credit Agreement, and other borrowings from third-party, external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

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

Off-Balance-Sheet Arrangements

At March 31, 2012, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

Long-Term Debt And Equity Financings 

NOTE 4 - LONG-TERM DEBT AND EQUITY FINANCINGS

Indenture Provisions and Other Covenants

Ameren Missouri's and Ameren Illinois' indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. However, a failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies' ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable for the 12 months ended March 31, 2012, at an assumed interest rate of 6% and dividend rate of 7%.

 

      Required Interest
Coverage Ratio (a)		    Actual Interest
Coverage Ratio		      Bonds Issuable (b)     Required Dividend
Coverage Ratio(c)		    Actual Dividend
Coverage Ratio		      Preferred Stock
Issuable		  

Ameren Missouri

    ³2.0      3.2       $ 2,004      ³2.5      85.1       $ 1,614   

Ameren Illinois

    ³2.0      7.2         3,373 (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 $89 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 in the respective company's articles of incorporation.
(d) Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture.

Ameren's indenture does not require Ameren to comply with any quantitative financial covenants. The indenture does, however, include certain cross-default provisions. Specifically, either (1) the failure by Ameren to pay when due and upon expiration of any applicable grace period any portion of any Ameren indebtedness in excess of $25 million or (2) the acceleration upon default of the maturity of any Ameren indebtedness in excess of $25 million under any indebtedness agreement, including the 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, Genco and certain other nonregistrant Ameren subsidiaries are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for any officer or director of a public utility, as defined in the Federal Power Act, to participate in the making or paying of any dividend from any funds "properly included in capital account." The meaning of this limitation has never been clarified under the Federal Power Act or FERC regulations. However, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividends are not excessive, and (3) there is no self-dealing on the part of corporate officials. At a minimum, Ameren believes that dividends can be paid by its subsidiaries that are public utilities from net income and retained earnings. In addition, under Illinois law, Ameren Illinois may not pay any dividend on its stock, unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless Ameren Illinois has specific authorization from the ICC.

Ameren Illinois' articles of incorporation require 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 after the Ameren Illinois Merger and AERG distribution. As of March 31, 2012, Ameren Illinois' ratio of common stock equity to total capitalization was 58%.

Genco's indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third party indebtedness. The following table summarizes these ratios for the 12 months ended and as of March 31, 2012:

 

      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)     3.66       £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 payments and, principal and interest payments on subordinated 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. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test.
(b) 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, for borrowed money. The ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Credit facility borrowings, including borrowings under the 2010 Genco Credit Agreement, and other borrowings from third-party, external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Genco's debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody's and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness.

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

Off-Balance-Sheet Arrangements

At March 31, 2012, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

Other Income And Expenses
Other Income And Expenses 

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents the components of "Other Income and Expenses" in Ameren's, Ameren Missouri's, and Ameren Illinois' statement of income (loss) and statements of income and comprehensive income for the three months ended March 31, 2012, and 2011:

 

     Three Months  
     2012      2011  

Ameren:(a)

     

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 9       $ 6   

Interest income on industrial development revenue bonds

      7         7   

Interest and dividend income

      —           1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 17       $ 16   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 12       $ 2   

Other

      3         3   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 15       $ 5   
  

 

 

     

 

 

  

Ameren Missouri:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 8       $ 6   

Interest income on industrial development revenue bonds

      7         7   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 15       $ 13   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations

    $ 2       $ 1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 3       $ 3   
  

 

 

     

 

 

  

Ameren Illinois:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 1       $ —     

Interest and dividend income

      —           1   

Other

      —           1   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 1       $ 2   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 10       $ —     

Other

      1         1   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 11       $ 1   
  

 

 

     

 

 

  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' participation in the formula ratemaking process.
Other Income And Expenses 

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents the components of "Other Income and Expenses" in Ameren's, Ameren Missouri's, and Ameren Illinois' statement of income (loss) and statements of income and comprehensive income for the three months ended March 31, 2012, and 2011:

 

     Three Months  
     2012      2011  

Ameren:(a)

     

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 9       $ 6   

Interest income on industrial development revenue bonds

      7         7   

Interest and dividend income

      —           1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 17       $ 16   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 12       $ 2   

Other

      3         3   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 15       $ 5   
  

 

 

     

 

 

  

Ameren Missouri:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 8       $ 6   

Interest income on industrial development revenue bonds

      7         7   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 15       $ 13   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations

    $ 2       $ 1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 3       $ 3   
  

 

 

     

 

 

  

Ameren Illinois:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 1       $ —     

Interest and dividend income

      —           1   

Other

      —           1   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 1       $ 2   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 10       $ —     

Other

      1         1   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 11       $ 1   
  

 

 

     

 

 

  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' participation in the formula ratemaking process.
Other Income And Expenses 

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents the components of "Other Income and Expenses" in Ameren's, Ameren Missouri's, and Ameren Illinois' statement of income (loss) and statements of income and comprehensive income for the three months ended March 31, 2012, and 2011:

 

     Three Months  
     2012      2011  

Ameren:(a)

     

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 9       $ 6   

Interest income on industrial development revenue bonds

      7         7   

Interest and dividend income

      —           1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 17       $ 16   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 12       $ 2   

Other

      3         3   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 15       $ 5   
  

 

 

     

 

 

  

Ameren Missouri:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 8       $ 6   

Interest income on industrial development revenue bonds

      7         7   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 15       $ 13   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations

    $ 2       $ 1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 3       $ 3   
  

 

 

     

 

 

  

Ameren Illinois:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 1       $ —     

Interest and dividend income

      —           1   

Other

      —           1   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 1       $ 2   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 10       $ —     

Other

      1         1   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 11       $ 1   
  

 

 

     

 

 

  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' participation in the formula ratemaking process.
Other Income And Expenses 

NOTE 5 - OTHER INCOME AND EXPENSES

The following table presents the components of "Other Income and Expenses" in Ameren's, Ameren Missouri's, and Ameren Illinois' statement of income (loss) and statements of income and comprehensive income for the three months ended March 31, 2012, and 2011:

 

     Three Months  
     2012      2011  

Ameren:(a)

     

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 9       $ 6   

Interest income on industrial development revenue bonds

      7         7   

Interest and dividend income

      —           1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 17       $ 16   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 12       $ 2   

Other

      3         3   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 15       $ 5   
  

 

 

     

 

 

  

Ameren Missouri:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 8       $ 6   

Interest income on industrial development revenue bonds

      7         7   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 15       $ 13   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations

    $ 2       $ 1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 3       $ 3   
  

 

 

     

 

 

  

Ameren Illinois:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 1       $ —     

Interest and dividend income

      —           1   

Other

      —           1   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 1       $ 2   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 10       $ —     

Other

      1         1   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 11       $ 1   
  

 

 

     

 

 

  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' participation in the formula ratemaking process.
Derivative Financial Instruments
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, electricity, and uranium. Such price fluctuations may cause the following:

 

  •  

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

 

  •  

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

 

  •  

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

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

 

The following table presents open gross derivative volumes by commodity type as of March 31, 2012, and December 31, 2011:

 

                                                                 
      Quantity (in millions, except as indicated)  
Commodity    NPNS Contracts(a)     Cash Flow Hedges(b)     Other Derivatives(c)     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2012     2011     2012     2011     2012     2011     2012     2011  

Coal (in tons)

                                                                 

Ameren Missouri

                      111                        116                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Genco

      22        24        (e )      (e )      3        (e )      (e )      (e ) 

Other(f)

      7        7        (e )      (e )      1        (e )      (e )      (e ) 

Ameren

      140        147        (e )      (e )      4        (e )      (e )      (e ) 

Fuel oils (in gallons)(g)

                                                                 

Ameren Missouri

      (e )      (e )      (e )      (e )      (e )      (e )      45        53   

Genco

      (e )      (e )      (e )      (e )      39        27        (e )      (e ) 

Other(f)

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

Ameren

      (e )      (e )      (e )      (e )      51        36        45        53   

Natural gas (in mmbtu)

                                                                 

Ameren Missouri

      7        8        (e )      (e )      14        9        22        19   

Ameren Illinois

      34        42        (e )      (e )      (e )      (e )      163        174   

Genco

      (e )      (e )      (e )      (e )      5        7        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      1        1        (e )      (e ) 

Ameren

      41        50        (e )      (e )      20        17        185        193   

Power (in megawatthours)

                                                                 

Ameren Missouri

      1        1        (e )      (e )      1        1        12        6   

Ameren Illinois

      23        11        (e )      (e )      (e )      (e )      21        24   

Genco

      (e )      (e )      (e )      (e )      -        -        (e )      (e ) 

Other(f)

      66        61        19        17        43        30        (7 )      (9 ) 

Ameren

      90        73        19        17        44        31        26        21   

Uranium (pounds in thousands)

                                                                 

Ameren Missouri & Ameren

      5,553        5,553        (e )      (e )      (e )      (e )      148        148   

 

(a) Contracts through December 2017, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of March 31, 2012.
(b) Contracts through December 2016 for power as of March 31, 2012.
(c) Contracts through December 2014, October 2015, January 2013, and November 2016 for coal, fuel oils, natural gas, and power, respectively, as of March 31, 2012.
(d) Contracts through October 2014, October 2016, May 2032, and December 2013 for fuel oils, natural gas, power, and uranium, respectively, as of March 31, 2012.
(e) Not applicable.
(f) Includes AERG contracts for coal and fuel oils, Marketing Company contracts for natural gas and power, and intercompany eliminations for power.
(g) Fuel oils consist of heating and crude oil.

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 or the statement of income and comprehensive income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income or the statement of income and comprehensive income.

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

 

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for 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 or the statement of income and comprehensive income in the period in which the change occurs.

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible financial instruments or other items.

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2012, and December 31, 2011:

 

                                     
      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

2012:

                                 

Derivative assets designated as hedging instruments

                                 

Commodity contracts:

                                      

Power

    MTM derivative assets    $ 19      $ -      $ (b )    $ -   
    

Other assets

      30        -        -        -   
    

Total assets

    $ 49      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                 

Commodity contracts:

                                      

Power

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

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Fuel oils

    MTM derivative assets    $ 36      $ 22      $ (b )    $ 11   
    

Other assets

      9        5        -        2   

Natural gas

    MTM derivative assets      5        2        (b )      2   
    

Other current assets

      -        -        1        -   
    

Other assets

      1        -        -        -   

Power

    MTM derivative assets      107        35        (b )      -   
    

Other assets

      29        -        -        -   
    

Total assets

    $ 187      $ 64      $ 1      $ 15   

Derivative liabilities not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Coal

    MTM derivative liabilities    $ 2      $ (b )    $ -      $  (b ) 
    

Other current liabilities

      -        -        -        1   
    

Other deferred credits and liabilities

      2        -        -        2   

Fuel oils

    Other deferred credits and liabilities      1        1        -        -   

Natural gas

    MTM derivative liabilities      120        (b )      102        (b ) 
    

Other current liabilities

      -        15        -        1   
    

Other deferred credits and liabilities

      95        13        82        -   

Power

    MTM derivative liabilities      97        (b )      20        (b ) 
    

MTM derivative liabilities - affiliates

      (b )      (b )      183        (b ) 
    

Other current liabilities

      -        15        -        -   
    

Other deferred credits and liabilities

      112        -        81        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 430      $ 45      $ 468      $ 4   

2011:

                                      

Derivative assets designated as hedging instruments

                                 

Commodity contracts:

                                      

Power

    MTM derivative assets    $ 8      $ -      $ (b )    $ -   
    

Other assets

      16        -        -        -   
    

Total assets

    $ 24      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                

Commodity contracts:

                                      

Power

    Other deferred credits and liabilities    $ 1      $ -      $ -      $ -   
    

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Fuel oils

    MTM derivative assets    $ 29      $ 17      $ (b )    $ 10   
    

Other assets

      8        6        -        1   

 

                                     
      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

Natural gas

    MTM derivative assets      6        2        (b )      2   
    

Other current assets

      -        -        1        -   
    

Other assets

      -        -        1        -   

Power

    MTM derivative assets      72        30        (b )      -   
    

Other assets

      99        -        77        -   
    

Total assets

    $ 214      $ 55      $ 79      $ 13   

Derivative liabilities not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Fuel oils

    MTM derivative liabilities    $ 2      $ (b )    $ -      $ (b ) 
    

Other current liabilities

      -        1        -        1   

Natural gas

    MTM derivative liabilities      106        (b )      90        (b ) 
    

Other current liabilities

      -        13        -        2   
    

Other deferred credits and liabilities

      92        13        79        -   

Power

    MTM derivative liabilities      53        (b )      9        (b ) 
    

MTM derivative liabilities - affiliates

      (b )      (b )      200        (b ) 
    

Other current liabilities

      -        9        -        -   
    

Other deferred credits and liabilities

      26        -        8        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 280      $ 37      $ 386      $ 3   

 

(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 March 31, 2012, and December 31, 2011:

 

                                         
      Ameren     Ameren Missouri     Ameren Illinois     Genco     Other(a)  

2012:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 41      $ -      $ -      $ -      $ 41   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

                                         

Fuel oils derivative contracts(e)

      24        24        -        -        -   

Natural gas derivative contracts(f)

      (209 )      (26 )      (183 )      -        -   

Power derivative contracts(g)

      (81 )      20        (284 )      -        183   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

2011:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 19      $ -      $ -      $ -      $ 19   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

                                         

Fuel oils derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (191 )      (24 )      (167 )      -        -   

Power derivative contracts(g)

      81        21        (140 )      -        200   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

 

(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 2016 as of March 31, 2012. Current gains of $14 million and $5 million were recorded at Ameren as of March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, was a loss of $8 million and $9 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e) Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through October 2014 as of March 31, 2012. Current gains deferred as regulatory liabilities include $20 million and $20 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current gains deferred as regulatory liabilities include $16 million and $16 million at Ameren and Ameren Missouri as of December 31, 2011, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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 March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $115 million, $13 million, and $102 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $101 million, $11 million, and $90 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.

(g) Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of March 31, 2012. Current gains deferred as regulatory liabilities include $34 million and $34 million at Ameren and Ameren Missouri, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $32 million, $13 million, and $203 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $17 million, $8 million, and $209 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.
(h) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of March 31, 2012. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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) the North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

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 March 31, 2012, and December 31, 2011, 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  

2012:

                                                                                 

AMO

    $ 1       $ -       $ 1       $ 9       $ 35       $ 4       $ -       $ -       $ 50    

AIC

      -         -         2         1         1         -         4         -         8    

Genco

      -         -         -         -         8         -         2         -         10    

Other(b)

      266         -         2         20         74         461         2         111         936    

Ameren

    $ 267       $ -       $ 5       $ 30       $ 118       $ 465       $ 8       $ 111       $     1,004    

2011:

                                                                                 

AMO

    $ 1       $ 35       $ 1       $ 4       $ 26       $ 4       $ -       $ -       $ 71    

AIC

      -         -         84         -         1         -         -         -         85    

Genco

      -         1         1         2         6         -         3         -         13    

Other(b)

      275         1         3         10         51         194         -         87         621    

Ameren

    $ 276       $ 37       $ 89       $ 16       $ 84       $ 198       $ 3       $ 87       $ 790    

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by Ameren Missouri and Marketing Company from counterparties and based on the contractual rights under the agreements to seek collateral, as well as the maximum exposure as calculated under the individual master trading and netting agreements, was $2 million and $4 million, respectively, from financial companies at March 31, 2012. Cash collateral held by Marketing Company was less than $1 million from retail companies at December 31, 2011. As of March 31, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of $7 million held by Ameren. As of December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million, $1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco, and Marketing Company, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2012, and December 31, 2011:

 

                                                                         
      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

      Oil and Gas
Companies		     

Retail

Companies

      Total  

2012:

                                                                                 

AMO

    $ 1       $ -       $ 1       $ 4       $ 28       $ 4       $ -       $ -       $ 38   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         -         -         -         3         -         -         -         3   

Other(b)

      266         -         1         9         67         455         2         110         910   

Ameren

    $ 267       $ -       $ 4       $ 13       $ 98       $ 459       $ 2       $ 110       $     953   

2011:

                                                                                 

AMO

    $ 1       $ 35       $ 1       $ 3       $ 22       $ 4       $ -       $ -       $ 66   

AIC

      -         -         84         -         -         -         -         -         84   

Genco

      -         -         -         1         1         -         2         -         4   

Other(b)

      273         -         3         5         42         187         -         86         596   

Ameren

    $ 274       $ 35       $ 88       $ 9       $ 65       $ 191       $ 2       $ 86       $ 750   

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in 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 March 31, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2012, or December 31, 2011, and (2) those counterparties with rights to do so requested collateral:

 

                         
     

Aggregate Fair Value of

Derivative Liabilities(a)

     

Cash

Collateral Posted

     

Potential Aggregate Amount of Additional

Collateral Required(b)

  

2012:

                           

Ameren Missouri

      $                    128         $                    8         $                    142   

Ameren Illinois

      223         109         111   

Genco

      57         -         61   

Other(c)

      82         12         66   

Ameren

      $                    490         $                129         $                    380   

2011:

                           

Ameren Missouri

      $                    102         $                    8         $                      86   

Ameren Illinois

      220         96         125   

Genco

      55         1         58   

Other(c)

      79         11         63   

Ameren

      $                     456         $                116         $                     332   

 

(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 months ended March 31, 2012, and 2011, associated with derivative instruments designated as 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)

  

2012:

                                   

Ameren:(d)

                                   

Power

    $ 18      Operating Revenues - Electric    $ 4      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2011:

                                   

Ameren:(d)

                                   

Power

    $ (4 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ (1 ) 

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 months ended March 31, 2012 and 2011:

 

                         
           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               2012     2011  
Ameren(a)    Coal    Operating Expenses - Fuel    $ (4 )    $ -   
     Fuel oils    Operating Expenses - Fuel      5        19   
     Natural gas (generation)    Operating Expenses - Fuel      1        -   
     Power    Operating Revenues - Electric      (1 )      (2 ) 
          Total    $ 1      $ 17   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ (1 ) 
Genco    Coal    Operating Expenses - Fuel    $ (3 )    $ -   
     Fuel oils    Operating Expenses - Fuel      4        15   
          Total    $ 1      $ 15   

 

(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 months ended March 31, 2012, and 2011:

 

                     
            Gain (Loss) Recognized in
Regulatory Liabilities or Regulatory Assets		  
            2012     2011  

Ameren(a)

    Fuel oils    $ 5      $ 29   
    

Natural gas

      (18 )      31   
    

Power

      (162 )      2   
    

Uranium

      -        (1 ) 
    

Total

    $ (175 )    $ 61   

Ameren

    Fuel oils    $ 5      $ 29   

Missouri

    Natural gas      (2 )      3   
    

Power

      (1 )      -   
    

Uranium

      -        (1 ) 
    

Total

    $ 2      $ 31   

Ameren Illinois

    Natural gas    $ (16 )    $ 28   
     Power      (144 )      27   
    

Total

    $ (160 )    $ 55   
(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. The fair value of the financial contracts included in "MTM derivative liabilities - affiliates" on Ameren Illinois' balance sheet totaled $183 million and $200 million at March 31, 2012, and December 31, 2011, respectively. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.

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, electricity, and uranium. Such price fluctuations may cause the following:

 

  •  

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

 

  •  

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

 

  •  

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

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

 

The following table presents open gross derivative volumes by commodity type as of March 31, 2012, and December 31, 2011:

 

      Quantity (in millions, except as indicated)  
Commodity    NPNS Contracts(a)     Cash Flow Hedges(b)     Other Derivatives(c)     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2012     2011     2012     2011     2012     2011     2012     2011  

Coal (in tons)

                 

Ameren Missouri

                      111                        116                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Genco

      22        24        (e )      (e )      3        (e )      (e )      (e ) 

Other(f)

      7        7        (e )      (e )      1        (e )      (e )      (e ) 

Ameren

      140        147        (e )      (e )      4        (e )      (e )      (e ) 

Fuel oils (in gallons)(g)

                 

Ameren Missouri

      (e )      (e )      (e )      (e )      (e )      (e )      45        53   

Genco

      (e )      (e )      (e )      (e )      39        27        (e )      (e ) 

Other(f)

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

Ameren

      (e )      (e )      (e )      (e )      51        36        45        53   

Natural gas (in mmbtu)

                 

Ameren Missouri

      7        8        (e )      (e )      14        9        22        19   

Ameren Illinois

      34        42        (e )      (e )      (e )      (e )      163        174   

Genco

      (e )      (e )      (e )      (e )      5        7        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      1        1        (e )      (e ) 

Ameren

      41        50        (e )      (e )      20        17        185        193   

Power (in megawatthours)

                 

Ameren Missouri

      1        1        (e )      (e )      1        1        12        6   

Ameren Illinois

      23        11        (e )      (e )      (e )      (e )      21        24   

Genco

      (e )      (e )      (e )      (e )      -        -        (e )      (e ) 

Other(f)

      66        61        19        17        43        30        (7 )      (9 ) 

Ameren

      90        73        19        17        44        31        26        21   

Uranium (pounds in thousands)

                 

Ameren Missouri & Ameren

      5,553        5,553        (e )      (e )      (e )      (e )      148        148   

 

(a) Contracts through December 2017, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of March 31, 2012.
(b) Contracts through December 2016 for power as of March 31, 2012.
(c) Contracts through December 2014, October 2015, January 2013, and November 2016 for coal, fuel oils, natural gas, and power, respectively, as of March 31, 2012.
(d) Contracts through October 2014, October 2016, May 2032, and December 2013 for fuel oils, natural gas, power, and uranium, respectively, as of March 31, 2012.
(e) Not applicable.
(f) Includes AERG contracts for coal and fuel oils, Marketing Company contracts for natural gas and power, and intercompany eliminations for power.
(g) Fuel oils consist of heating and crude oil.

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 or the statement of income and comprehensive income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income or the statement of income and comprehensive income.

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

 

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for 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 or the statement of income and comprehensive income in the period in which the change occurs.

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible financial instruments or other items.

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2012, and December 31, 2011:

 

      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

2012:

         

Derivative assets designated as hedging instruments

         

Commodity contracts:

            

Power

    MTM derivative assets    $ 19      $ -      $ (b )    $ -   
  

Other assets

      30        -        -        -   
    

Total assets

    $ 49      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

         

Commodity contracts:

            

Power

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

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative assets    $ 36      $ 22      $ (b )    $ 11   
  

Other assets

      9        5        -        2   

Natural gas

    MTM derivative assets      5        2        (b )      2   
  

Other current assets

      -        -        1        -   
  

Other assets

      1        -        -        -   

Power

    MTM derivative assets      107        35        (b )      -   
  

Other assets

      29        -        -        -   
    

Total assets

    $ 187      $ 64      $ 1      $ 15   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Coal

    MTM derivative liabilities    $ 2      $ (b )    $ -      $  (b ) 
  

Other current liabilities

      -        -        -        1   
  

Other deferred credits and liabilities

      2        -        -        2   

Fuel oils

    Other deferred credits and liabilities      1        1        -        -   

Natural gas

    MTM derivative liabilities      120        (b )      102        (b ) 
  

Other current liabilities

      -        15        -        1   
  

Other deferred credits and liabilities

      95        13        82        -   

Power

    MTM derivative liabilities      97        (b )      20        (b ) 
  

MTM derivative liabilities - affiliates

      (b )      (b )      183        (b ) 
  

Other current liabilities

      -        15        -        -   
  

Other deferred credits and liabilities

      112        -        81        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 430      $ 45      $ 468      $ 4   

2011:

            

Derivative assets designated as hedging instruments

         

Commodity contracts:

            

Power

    MTM derivative assets    $ 8      $ -      $ (b )    $ -   
  

Other assets

      16        -        -        -   
    

Total assets

    $ 24      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

        

Commodity contracts:

            

Power

    Other deferred credits and liabilities    $ 1      $ -      $ -      $ -   
    

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative assets    $ 29      $ 17      $ (b )    $ 10   
    

Other assets

      8        6        -        1   

 

      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

Natural gas

    MTM derivative assets      6        2        (b )      2   
  

Other current assets

      -        -        1        -   
  

Other assets

      -        -        1        -   

Power

    MTM derivative assets      72        30        (b )      -   
  

Other assets

      99        -        77        -   
    

Total assets

    $ 214      $ 55      $ 79      $ 13   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative liabilities    $ 2      $ (b )    $ -      $ (b ) 
  

Other current liabilities

      -        1        -        1   

Natural gas

    MTM derivative liabilities      106        (b )      90        (b ) 
  

Other current liabilities

      -        13        -        2   
  

Other deferred credits and liabilities

      92        13        79        -   

Power

    MTM derivative liabilities      53        (b )      9        (b ) 
  

MTM derivative liabilities - affiliates

      (b )      (b )      200        (b ) 
  

Other current liabilities

      -        9        -        -   
  

Other deferred credits and liabilities

      26        -        8        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 280      $ 37      $ 386      $ 3   

 

(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 March 31, 2012, and December 31, 2011:

 

      Ameren     Ameren Missouri     Ameren Illinois     Genco     Other(a)  

2012:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 41      $ -      $ -      $ -      $ 41   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

           

Fuel oils derivative contracts(e)

      24        24        -        -        -   

Natural gas derivative contracts(f)

      (209 )      (26 )      (183 )      -        -   

Power derivative contracts(g)

      (81 )      20        (284 )      -        183   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

2011:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 19      $ -      $ -      $ -      $ 19   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

           

Fuel oils derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (191 )      (24 )      (167 )      -        -   

Power derivative contracts(g)

      81        21        (140 )      -        200   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

 

(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 2016 as of March 31, 2012. Current gains of $14 million and $5 million were recorded at Ameren as of March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, was a loss of $8 million and $9 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e) Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through October 2014 as of March 31, 2012. Current gains deferred as regulatory liabilities include $20 million and $20 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current gains deferred as regulatory liabilities include $16 million and $16 million at Ameren and Ameren Missouri as of December 31, 2011, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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 March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $115 million, $13 million, and $102 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $101 million, $11 million, and $90 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.

(g) Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of March 31, 2012. Current gains deferred as regulatory liabilities include $34 million and $34 million at Ameren and Ameren Missouri, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $32 million, $13 million, and $203 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $17 million, $8 million, and $209 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.
(h) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of March 31, 2012. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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) the North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

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 March 31, 2012, and December 31, 2011, 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  

2012:

                           

AMO

    $ 1       $ -       $ 1       $ 9       $ 35       $ 4       $ -       $ -       $ 50    

AIC

      -         -         2         1         1         -         4         -         8    

Genco

      -         -         -         -         8         -         2         -         10    

Other(b)

      266         -         2         20         74         461         2         111         936    

Ameren

    $ 267       $ -       $ 5       $ 30       $ 118       $ 465       $ 8       $ 111       $     1,004    

2011:

                           

AMO

    $ 1       $ 35       $ 1       $ 4       $ 26       $ 4       $ -       $ -       $ 71    

AIC

      -         -         84         -         1         -         -         -         85    

Genco

      -         1         1         2         6         -         3         -         13    

Other(b)

      275         1         3         10         51         194         -         87         621    

Ameren

    $ 276       $ 37       $ 89       $ 16       $ 84       $ 198       $ 3       $ 87       $ 790    

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by Ameren Missouri and Marketing Company from counterparties and based on the contractual rights under the agreements to seek collateral, as well as the maximum exposure as calculated under the individual master trading and netting agreements, was $2 million and $4 million, respectively, from financial companies at March 31, 2012. Cash collateral held by Marketing Company was less than $1 million from retail companies at December 31, 2011. As of March 31, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of $7 million held by Ameren. As of December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million, $1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco, and Marketing Company, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2012, and December 31, 2011:

 

      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

      Oil and Gas
Companies		     

Retail

Companies

      Total  

2012:

                           

AMO

    $ 1       $ -       $ 1       $ 4       $ 28       $ 4       $ -       $ -       $ 38   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         -         -         -         3         -         -         -         3   

Other(b)

      266         -         1         9         67         455         2         110         910   

Ameren

    $ 267       $ -       $ 4       $ 13       $ 98       $ 459       $ 2       $ 110       $     953   

2011:

                           

AMO

    $ 1       $ 35       $ 1       $ 3       $ 22       $ 4       $ -       $ -       $ 66   

AIC

      -         -         84         -         -         -         -         -         84   

Genco

      -         -         -         1         1         -         2         -         4   

Other(b)

      273         -         3         5         42         187         -         86         596   

Ameren

    $ 274       $ 35       $ 88       $ 9       $ 65       $ 191       $ 2       $ 86       $ 750   

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in 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 March 31, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2012, or December 31, 2011, and (2) those counterparties with rights to do so requested collateral:

 

     

Aggregate Fair Value of

Derivative Liabilities(a)

     

Cash

Collateral Posted

     

Potential Aggregate Amount of Additional

Collateral Required(b)

  

2012:

         

Ameren Missouri

      $                    128         $                    8         $                    142   

Ameren Illinois

      223         109         111   

Genco

      57         -         61   

Other(c)

      82         12         66   

Ameren

      $                    490         $                129         $                    380   

2011:

                           

Ameren Missouri

      $                    102         $                    8         $                      86   

Ameren Illinois

      220         96         125   

Genco

      55         1         58   

Other(c)

      79         11         63   

Ameren

      $                     456         $                116         $                     332   

 

(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 months ended March 31, 2012, and 2011, associated with derivative instruments designated as 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)

  

2012:

             

Ameren:(d)

             

Power

    $ 18      Operating Revenues - Electric    $ 4      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2011:

             

Ameren:(d)

             

Power

    $ (4 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ (1 ) 

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 months ended March 31, 2012 and 2011:

 

           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               2012     2011  
Ameren(a)    Coal    Operating Expenses - Fuel    $ (4 )    $ -   
   Fuel oils    Operating Expenses - Fuel      5        19   
   Natural gas (generation)    Operating Expenses - Fuel      1        -   
     Power    Operating Revenues - Electric      (1 )      (2 ) 
          Total    $ 1      $ 17   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ (1 ) 
Genco    Coal    Operating Expenses - Fuel    $ (3 )    $ -   
     Fuel oils    Operating Expenses - Fuel      4        15   
          Total    $ 1      $ 15   

 

(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 months ended March 31, 2012, and 2011:

 

            Gain (Loss) Recognized in
Regulatory Liabilities or Regulatory Assets		  
            2012     2011  

Ameren(a)

    Fuel oils    $ 5      $ 29   
  

Natural gas

      (18 )      31   
  

Power

      (162 )      2   
    

Uranium

      -        (1 ) 
    

Total

    $ (175 )    $ 61   

Ameren

    Fuel oils    $ 5      $ 29   

Missouri

    Natural gas      (2 )      3   
  

Power

      (1 )      -   
    

Uranium

      -        (1 ) 
    

Total

    $ 2      $ 31   

Ameren Illinois

    Natural gas    $ (16 )    $ 28   
     Power      (144 )      27   
    

Total

    $ (160 )    $ 55   
(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. The fair value of the financial contracts included in "MTM derivative liabilities - affiliates" on Ameren Illinois' balance sheet totaled $183 million and $200 million at March 31, 2012, and December 31, 2011, respectively. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.

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, electricity, and uranium. Such price fluctuations may cause the following:

 

  •  

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

 

  •  

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

 

  •  

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

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

 

The following table presents open gross derivative volumes by commodity type as of March 31, 2012, and December 31, 2011:

 

      Quantity (in millions, except as indicated)  
Commodity    NPNS Contracts(a)     Cash Flow Hedges(b)     Other Derivatives(c)     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2012     2011     2012     2011     2012     2011     2012     2011  

Coal (in tons)

                 

Ameren Missouri

                      111                        116                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Genco

      22        24        (e )      (e )      3        (e )      (e )      (e ) 

Other(f)

      7        7        (e )      (e )      1        (e )      (e )      (e ) 

Ameren

      140        147        (e )      (e )      4        (e )      (e )      (e ) 

Fuel oils (in gallons)(g)

                 

Ameren Missouri

      (e )      (e )      (e )      (e )      (e )      (e )      45        53   

Genco

      (e )      (e )      (e )      (e )      39        27        (e )      (e ) 

Other(f)

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

Ameren

      (e )      (e )      (e )      (e )      51        36        45        53   

Natural gas (in mmbtu)

                 

Ameren Missouri

      7        8        (e )      (e )      14        9        22        19   

Ameren Illinois

      34        42        (e )      (e )      (e )      (e )      163        174   

Genco

      (e )      (e )      (e )      (e )      5        7        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      1        1        (e )      (e ) 

Ameren

      41        50        (e )      (e )      20        17        185        193   

Power (in megawatthours)

                 

Ameren Missouri

      1        1        (e )      (e )      1        1        12        6   

Ameren Illinois

      23        11        (e )      (e )      (e )      (e )      21        24   

Genco

      (e )      (e )      (e )      (e )      -        -        (e )      (e ) 

Other(f)

      66        61        19        17        43        30        (7 )      (9 ) 

Ameren

      90        73        19        17        44        31        26        21   

Uranium (pounds in thousands)

                 

Ameren Missouri & Ameren

      5,553        5,553        (e )      (e )      (e )      (e )      148        148   

 

(a) Contracts through December 2017, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of March 31, 2012.
(b) Contracts through December 2016 for power as of March 31, 2012.
(c) Contracts through December 2014, October 2015, January 2013, and November 2016 for coal, fuel oils, natural gas, and power, respectively, as of March 31, 2012.
(d) Contracts through October 2014, October 2016, May 2032, and December 2013 for fuel oils, natural gas, power, and uranium, respectively, as of March 31, 2012.
(e) Not applicable.
(f) Includes AERG contracts for coal and fuel oils, Marketing Company contracts for natural gas and power, and intercompany eliminations for power.
(g) Fuel oils consist of heating and crude oil.

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 or the statement of income and comprehensive income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income or the statement of income and comprehensive income.

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

 

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for 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 or the statement of income and comprehensive income in the period in which the change occurs.

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible financial instruments or other items.

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2012, and December 31, 2011:

 

      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

2012:

         

Derivative assets designated as hedging instruments

         

Commodity contracts:

            

Power

    MTM derivative assets    $ 19      $ -      $ (b )    $ -   
  

Other assets

      30        -        -        -   
    

Total assets

    $ 49      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

         

Commodity contracts:

            

Power

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

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative assets    $ 36      $ 22      $ (b )    $ 11   
  

Other assets

      9        5        -        2   

Natural gas

    MTM derivative assets      5        2        (b )      2   
  

Other current assets

      -        -        1        -   
  

Other assets

      1        -        -        -   

Power

    MTM derivative assets      107        35        (b )      -   
  

Other assets

      29        -        -        -   
    

Total assets

    $ 187      $ 64      $ 1      $ 15   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Coal

    MTM derivative liabilities    $ 2      $ (b )    $ -      $  (b ) 
  

Other current liabilities

      -        -        -        1   
  

Other deferred credits and liabilities

      2        -        -        2   

Fuel oils

    Other deferred credits and liabilities      1        1        -        -   

Natural gas

    MTM derivative liabilities      120        (b )      102        (b ) 
  

Other current liabilities

      -        15        -        1   
  

Other deferred credits and liabilities

      95        13        82        -   

Power

    MTM derivative liabilities      97        (b )      20        (b ) 
  

MTM derivative liabilities - affiliates

      (b )      (b )      183        (b ) 
  

Other current liabilities

      -        15        -        -   
  

Other deferred credits and liabilities

      112        -        81        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 430      $ 45      $ 468      $ 4   

2011:

            

Derivative assets designated as hedging instruments

         

Commodity contracts:

            

Power

    MTM derivative assets    $ 8      $ -      $ (b )    $ -   
  

Other assets

      16        -        -        -   
    

Total assets

    $ 24      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

        

Commodity contracts:

            

Power

    Other deferred credits and liabilities    $ 1      $ -      $ -      $ -   
    

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative assets    $ 29      $ 17      $ (b )    $ 10   
    

Other assets

      8        6        -        1   

 

      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

Natural gas

    MTM derivative assets      6        2        (b )      2   
  

Other current assets

      -        -        1        -   
  

Other assets

      -        -        1        -   

Power

    MTM derivative assets      72        30        (b )      -   
  

Other assets

      99        -        77        -   
    

Total assets

    $ 214      $ 55      $ 79      $ 13   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative liabilities    $ 2      $ (b )    $ -      $ (b ) 
  

Other current liabilities

      -        1        -        1   

Natural gas

    MTM derivative liabilities      106        (b )      90        (b ) 
  

Other current liabilities

      -        13        -        2   
  

Other deferred credits and liabilities

      92        13        79        -   

Power

    MTM derivative liabilities      53        (b )      9        (b ) 
  

MTM derivative liabilities - affiliates

      (b )      (b )      200        (b ) 
  

Other current liabilities

      -        9        -        -   
  

Other deferred credits and liabilities

      26        -        8        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 280      $ 37      $ 386      $ 3   

 

(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 March 31, 2012, and December 31, 2011:

 

      Ameren     Ameren Missouri     Ameren Illinois     Genco     Other(a)  

2012:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 41      $ -      $ -      $ -      $ 41   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

           

Fuel oils derivative contracts(e)

      24        24        -        -        -   

Natural gas derivative contracts(f)

      (209 )      (26 )      (183 )      -        -   

Power derivative contracts(g)

      (81 )      20        (284 )      -        183   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

2011:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 19      $ -      $ -      $ -      $ 19   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

           

Fuel oils derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (191 )      (24 )      (167 )      -        -   

Power derivative contracts(g)

      81        21        (140 )      -        200   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

 

(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 2016 as of March 31, 2012. Current gains of $14 million and $5 million were recorded at Ameren as of March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, was a loss of $8 million and $9 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e) Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through October 2014 as of March 31, 2012. Current gains deferred as regulatory liabilities include $20 million and $20 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current gains deferred as regulatory liabilities include $16 million and $16 million at Ameren and Ameren Missouri as of December 31, 2011, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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 March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $115 million, $13 million, and $102 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $101 million, $11 million, and $90 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.

(g) Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of March 31, 2012. Current gains deferred as regulatory liabilities include $34 million and $34 million at Ameren and Ameren Missouri, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $32 million, $13 million, and $203 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $17 million, $8 million, and $209 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.
(h) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of March 31, 2012. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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) the North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

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 March 31, 2012, and December 31, 2011, 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  

2012:

                           

AMO

    $ 1       $ -       $ 1       $ 9       $ 35       $ 4       $ -       $ -       $ 50    

AIC

      -         -         2         1         1         -         4         -         8    

Genco

      -         -         -         -         8         -         2         -         10    

Other(b)

      266         -         2         20         74         461         2         111         936    

Ameren

    $ 267       $ -       $ 5       $ 30       $ 118       $ 465       $ 8       $ 111       $     1,004    

2011:

                           

AMO

    $ 1       $ 35       $ 1       $ 4       $ 26       $ 4       $ -       $ -       $ 71    

AIC

      -         -         84         -         1         -         -         -         85    

Genco

      -         1         1         2         6         -         3         -         13    

Other(b)

      275         1         3         10         51         194         -         87         621    

Ameren

    $ 276       $ 37       $ 89       $ 16       $ 84       $ 198       $ 3       $ 87       $ 790    

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by Ameren Missouri and Marketing Company from counterparties and based on the contractual rights under the agreements to seek collateral, as well as the maximum exposure as calculated under the individual master trading and netting agreements, was $2 million and $4 million, respectively, from financial companies at March 31, 2012. Cash collateral held by Marketing Company was less than $1 million from retail companies at December 31, 2011. As of March 31, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of $7 million held by Ameren. As of December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million, $1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco, and Marketing Company, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2012, and December 31, 2011:

 

      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

      Oil and Gas
Companies		     

Retail

Companies

      Total  

2012:

                           

AMO

    $ 1       $ -       $ 1       $ 4       $ 28       $ 4       $ -       $ -       $ 38   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         -         -         -         3         -         -         -         3   

Other(b)

      266         -         1         9         67         455         2         110         910   

Ameren

    $ 267       $ -       $ 4       $ 13       $ 98       $ 459       $ 2       $ 110       $     953   

2011:

                           

AMO

    $ 1       $ 35       $ 1       $ 3       $ 22       $ 4       $ -       $ -       $ 66   

AIC

      -         -         84         -         -         -         -         -         84   

Genco

      -         -         -         1         1         -         2         -         4   

Other(b)

      273         -         3         5         42         187         -         86         596   

Ameren

    $ 274       $ 35       $ 88       $ 9       $ 65       $ 191       $ 2       $ 86       $ 750   

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in 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 March 31, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2012, or December 31, 2011, and (2) those counterparties with rights to do so requested collateral:

 

     

Aggregate Fair Value of

Derivative Liabilities(a)

     

Cash

Collateral Posted

     

Potential Aggregate Amount of Additional

Collateral Required(b)

  

2012:

         

Ameren Missouri

      $                    128         $                    8         $                    142   

Ameren Illinois

      223         109         111   

Genco

      57         -         61   

Other(c)

      82         12         66   

Ameren

      $                    490         $                129         $                    380   

2011:

                           

Ameren Missouri

      $                    102         $                    8         $                      86   

Ameren Illinois

      220         96         125   

Genco

      55         1         58   

Other(c)

      79         11         63   

Ameren

      $                     456         $                116         $                     332   

 

(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 months ended March 31, 2012, and 2011, associated with derivative instruments designated as 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)

  

2012:

             

Ameren:(d)

             

Power

    $ 18      Operating Revenues - Electric    $ 4      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2011:

             

Ameren:(d)

             

Power

    $ (4 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ (1 ) 

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 months ended March 31, 2012 and 2011:

 

           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               2012     2011  
Ameren(a)    Coal    Operating Expenses - Fuel    $ (4 )    $ -   
   Fuel oils    Operating Expenses - Fuel      5        19   
   Natural gas (generation)    Operating Expenses - Fuel      1        -   
     Power    Operating Revenues - Electric      (1 )      (2 ) 
          Total    $ 1      $ 17   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ (1 ) 
Genco    Coal    Operating Expenses - Fuel    $ (3 )    $ -   
     Fuel oils    Operating Expenses - Fuel      4        15   
          Total    $ 1      $ 15   

 

(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 months ended March 31, 2012, and 2011:

 

            Gain (Loss) Recognized in
Regulatory Liabilities or Regulatory Assets		  
            2012     2011  

Ameren(a)

    Fuel oils    $ 5      $ 29   
  

Natural gas

      (18 )      31   
  

Power

      (162 )      2   
    

Uranium

      -        (1 ) 
    

Total

    $ (175 )    $ 61   

Ameren

    Fuel oils    $ 5      $ 29   

Missouri

    Natural gas      (2 )      3   
  

Power

      (1 )      -   
    

Uranium

      -        (1 ) 
    

Total

    $ 2      $ 31   

Ameren Illinois

    Natural gas    $ (16 )    $ 28   
     Power      (144 )      27   
    

Total

    $ (160 )    $ 55   
(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. The fair value of the financial contracts included in "MTM derivative liabilities - affiliates" on Ameren Illinois' balance sheet totaled $183 million and $200 million at March 31, 2012, and December 31, 2011, respectively. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.

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, electricity, and uranium. Such price fluctuations may cause the following:

 

  •  

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

 

  •  

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

 

  •  

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

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

 

The following table presents open gross derivative volumes by commodity type as of March 31, 2012, and December 31, 2011:

 

      Quantity (in millions, except as indicated)  
Commodity    NPNS Contracts(a)     Cash Flow Hedges(b)     Other Derivatives(c)     Derivatives That Qualify for
Regulatory Deferral(d)		  
     2012     2011     2012     2011     2012     2011     2012     2011  

Coal (in tons)

                 

Ameren Missouri

                      111                        116                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Genco

      22        24        (e )      (e )      3        (e )      (e )      (e ) 

Other(f)

      7        7        (e )      (e )      1        (e )      (e )      (e ) 

Ameren

      140        147        (e )      (e )      4        (e )      (e )      (e ) 

Fuel oils (in gallons)(g)

                 

Ameren Missouri

      (e )      (e )      (e )      (e )      (e )      (e )      45        53   

Genco

      (e )      (e )      (e )      (e )      39        27        (e )      (e ) 

Other(f)

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

Ameren

      (e )      (e )      (e )      (e )      51        36        45        53   

Natural gas (in mmbtu)

                 

Ameren Missouri

      7        8        (e )      (e )      14        9        22        19   

Ameren Illinois

      34        42        (e )      (e )      (e )      (e )      163        174   

Genco

      (e )      (e )      (e )      (e )      5        7        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      1        1        (e )      (e ) 

Ameren

      41        50        (e )      (e )      20        17        185        193   

Power (in megawatthours)

                 

Ameren Missouri

      1        1        (e )      (e )      1        1        12        6   

Ameren Illinois

      23        11        (e )      (e )      (e )      (e )      21        24   

Genco

      (e )      (e )      (e )      (e )      -        -        (e )      (e ) 

Other(f)

      66        61        19        17        43        30        (7 )      (9 ) 

Ameren

      90        73        19        17        44        31        26        21   

Uranium (pounds in thousands)

                 

Ameren Missouri & Ameren

      5,553        5,553        (e )      (e )      (e )      (e )      148        148   

 

(a) Contracts through December 2017, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of March 31, 2012.
(b) Contracts through December 2016 for power as of March 31, 2012.
(c) Contracts through December 2014, October 2015, January 2013, and November 2016 for coal, fuel oils, natural gas, and power, respectively, as of March 31, 2012.
(d) Contracts through October 2014, October 2016, May 2032, and December 2013 for fuel oils, natural gas, power, and uranium, respectively, as of March 31, 2012.
(e) Not applicable.
(f) Includes AERG contracts for coal and fuel oils, Marketing Company contracts for natural gas and power, and intercompany eliminations for power.
(g) Fuel oils consist of heating and crude oil.

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 or the statement of income and comprehensive income in the period in which the change occurs. When the contract is settled or delivered, the net gain or loss is recorded in the statement of income or the statement of income and comprehensive income.

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

 

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for 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 or the statement of income and comprehensive income in the period in which the change occurs.

Authoritative accounting guidance permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. The Ameren Companies did not elect to adopt this guidance for any eligible financial instruments or other items.

The following table presents the carrying value and balance sheet location of all derivative instruments as of March 31, 2012, and December 31, 2011:

 

      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

2012:

         

Derivative assets designated as hedging instruments

         

Commodity contracts:

            

Power

    MTM derivative assets    $ 19      $ -      $ (b )    $ -   
  

Other assets

      30        -        -        -   
    

Total assets

    $ 49      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

         

Commodity contracts:

            

Power

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

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative assets    $ 36      $ 22      $ (b )    $ 11   
  

Other assets

      9        5        -        2   

Natural gas

    MTM derivative assets      5        2        (b )      2   
  

Other current assets

      -        -        1        -   
  

Other assets

      1        -        -        -   

Power

    MTM derivative assets      107        35        (b )      -   
  

Other assets

      29        -        -        -   
    

Total assets

    $ 187      $ 64      $ 1      $ 15   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Coal

    MTM derivative liabilities    $ 2      $ (b )    $ -      $  (b ) 
  

Other current liabilities

      -        -        -        1   
  

Other deferred credits and liabilities

      2        -        -        2   

Fuel oils

    Other deferred credits and liabilities      1        1        -        -   

Natural gas

    MTM derivative liabilities      120        (b )      102        (b ) 
  

Other current liabilities

      -        15        -        1   
  

Other deferred credits and liabilities

      95        13        82        -   

Power

    MTM derivative liabilities      97        (b )      20        (b ) 
  

MTM derivative liabilities - affiliates

      (b )      (b )      183        (b ) 
  

Other current liabilities

      -        15        -        -   
  

Other deferred credits and liabilities

      112        -        81        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 430      $ 45      $ 468      $ 4   

2011:

            

Derivative assets designated as hedging instruments

         

Commodity contracts:

            

Power

    MTM derivative assets    $ 8      $ -      $ (b )    $ -   
  

Other assets

      16        -        -        -   
    

Total assets

    $ 24      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

        

Commodity contracts:

            

Power

    Other deferred credits and liabilities    $ 1      $ -      $ -      $ -   
    

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative assets    $ 29      $ 17      $ (b )    $ 10   
    

Other assets

      8        6        -        1   

 

      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

Natural gas

    MTM derivative assets      6        2        (b )      2   
  

Other current assets

      -        -        1        -   
  

Other assets

      -        -        1        -   

Power

    MTM derivative assets      72        30        (b )      -   
  

Other assets

      99        -        77        -   
    

Total assets

    $ 214      $ 55      $ 79      $ 13   

Derivative liabilities not designated as hedging instruments(c)

         

Commodity contracts:

            

Fuel oils

    MTM derivative liabilities    $ 2      $ (b )    $ -      $ (b ) 
  

Other current liabilities

      -        1        -        1   

Natural gas

    MTM derivative liabilities      106        (b )      90        (b ) 
  

Other current liabilities

      -        13        -        2   
  

Other deferred credits and liabilities

      92        13        79        -   

Power

    MTM derivative liabilities      53        (b )      9        (b ) 
  

MTM derivative liabilities - affiliates

      (b )      (b )      200        (b ) 
  

Other current liabilities

      -        9        -        -   
  

Other deferred credits and liabilities

      26        -        8        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 280      $ 37      $ 386      $ 3   

 

(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 March 31, 2012, and December 31, 2011:

 

      Ameren     Ameren Missouri     Ameren Illinois     Genco     Other(a)  

2012:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 41      $ -      $ -      $ -      $ 41   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

           

Fuel oils derivative contracts(e)

      24        24        -        -        -   

Natural gas derivative contracts(f)

      (209 )      (26 )      (183 )      -        -   

Power derivative contracts(g)

      (81 )      20        (284 )      -        183   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

2011:

           

Cumulative gains (losses) deferred in accumulated OCI:

           

Power derivative contracts(b)

    $ 19      $ -      $ -      $ -      $ 19   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

           

Fuel oils derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (191 )      (24 )      (167 )      -        -   

Power derivative contracts(g)

      81        21        (140 )      -        200   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

 

(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 2016 as of March 31, 2012. Current gains of $14 million and $5 million were recorded at Ameren as of March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, was a loss of $8 million and $9 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e) Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through October 2014 as of March 31, 2012. Current gains deferred as regulatory liabilities include $20 million and $20 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current gains deferred as regulatory liabilities include $16 million and $16 million at Ameren and Ameren Missouri as of December 31, 2011, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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 March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $115 million, $13 million, and $102 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $101 million, $11 million, and $90 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.

(g) Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of March 31, 2012. Current gains deferred as regulatory liabilities include $34 million and $34 million at Ameren and Ameren Missouri, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $32 million, $13 million, and $203 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $17 million, $8 million, and $209 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.
(h) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of March 31, 2012. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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) the North American Energy Standards Board Inc. agreement, a standardized contract for the purchase and sale of natural gas. These master trading and netting agreements allow the counterparties to net settle sale and purchase transactions. Further, collateral requirements are calculated at a master trading and netting agreement level by counterparty.

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 March 31, 2012, and December 31, 2011, 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  

2012:

                           

AMO

    $ 1       $ -       $ 1       $ 9       $ 35       $ 4       $ -       $ -       $ 50    

AIC

      -         -         2         1         1         -         4         -         8    

Genco

      -         -         -         -         8         -         2         -         10    

Other(b)

      266         -         2         20         74         461         2         111         936    

Ameren

    $ 267       $ -       $ 5       $ 30       $ 118       $ 465       $ 8       $ 111       $     1,004    

2011:

                           

AMO

    $ 1       $ 35       $ 1       $ 4       $ 26       $ 4       $ -       $ -       $ 71    

AIC

      -         -         84         -         1         -         -         -         85    

Genco

      -         1         1         2         6         -         3         -         13    

Other(b)

      275         1         3         10         51         194         -         87         621    

Ameren

    $ 276       $ 37       $ 89       $ 16       $ 84       $ 198       $ 3       $ 87       $ 790    

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.

The potential loss on counterparty exposures is reduced by the application of master trading and netting agreements and collateral held to the extent of reducing the exposure to zero. Collateral includes both cash collateral and other collateral held. The amount of cash collateral held by Ameren Missouri and Marketing Company from counterparties and based on the contractual rights under the agreements to seek collateral, as well as the maximum exposure as calculated under the individual master trading and netting agreements, was $2 million and $4 million, respectively, from financial companies at March 31, 2012. Cash collateral held by Marketing Company was less than $1 million from retail companies at December 31, 2011. As of March 31, 2012, other collateral used to reduce exposure consisted of letters of credit in the amount of $7 million held by Ameren. As of December 31, 2011, other collateral used to reduce exposure consisted of letters of credit in the amount of $9 million, $1 million, $1 million, and $7 million held by Ameren, Ameren Missouri, Genco, and Marketing Company, respectively. The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of March 31, 2012, and December 31, 2011:

 

      Affiliates(a)     

Coal

Producers

     

Commodity
Marketing

Companies

     

Electric

Utilities

     

Financial

Companies

     

Municipalities/

Cooperatives

      Oil and Gas
Companies		     

Retail

Companies

      Total  

2012:

                           

AMO

    $ 1       $ -       $ 1       $ 4       $ 28       $ 4       $ -       $ -       $ 38   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         -         -         -         3         -         -         -         3   

Other(b)

      266         -         1         9         67         455         2         110         910   

Ameren

    $ 267       $ -       $ 4       $ 13       $ 98       $ 459       $ 2       $ 110       $     953   

2011:

                           

AMO

    $ 1       $ 35       $ 1       $ 3       $ 22       $ 4       $ -       $ -       $ 66   

AIC

      -         -         84         -         -         -         -         -         84   

Genco

      -         -         -         1         1         -         2         -         4   

Other(b)

      273         -         3         5         42         187         -         86         596   

Ameren

    $ 274       $ 35       $ 88       $ 9       $ 65       $ 191       $ 2       $ 86       $ 750   

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in 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 March 31, 2012, and December 31, 2011, the aggregate fair value of all derivative instruments with credit risk-related contingent features in a gross liability position, the cash collateral posted, and the aggregate amount of additional collateral that could be required to be posted with counterparties. The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on March 31, 2012, or December 31, 2011, and (2) those counterparties with rights to do so requested collateral:

 

     

Aggregate Fair Value of

Derivative Liabilities(a)

     

Cash

Collateral Posted

     

Potential Aggregate Amount of Additional

Collateral Required(b)

  

2012:

         

Ameren Missouri

      $                    128         $                    8         $                    142   

Ameren Illinois

      223         109         111   

Genco

      57         -         61   

Other(c)

      82         12         66   

Ameren

      $                    490         $                129         $                    380   

2011:

                           

Ameren Missouri

      $                    102         $                    8         $                      86   

Ameren Illinois

      220         96         125   

Genco

      55         1         58   

Other(c)

      79         11         63   

Ameren

      $                     456         $                116         $                     332   

 

(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 months ended March 31, 2012, and 2011, associated with derivative instruments designated as 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)

  

2012:

             

Ameren:(d)

             

Power

    $ 18      Operating Revenues - Electric    $ 4      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

             

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2011:

             

Ameren:(d)

             

Power

    $ (4 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ (1 ) 

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 months ended March 31, 2012 and 2011:

 

           

Location of Gain (Loss)

Recognized in Income

   

Gain (Loss)

Recognized in Income

  
               2012     2011  
Ameren(a)    Coal    Operating Expenses - Fuel    $ (4 )    $ -   
   Fuel oils    Operating Expenses - Fuel      5        19   
   Natural gas (generation)    Operating Expenses - Fuel      1        -   
     Power    Operating Revenues - Electric      (1 )      (2 ) 
          Total    $ 1      $ 17   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ (1 ) 
Genco    Coal    Operating Expenses - Fuel    $ (3 )    $ -   
     Fuel oils    Operating Expenses - Fuel      4        15   
          Total    $ 1      $ 15   

 

(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 months ended March 31, 2012, and 2011:

 

            Gain (Loss) Recognized in
Regulatory Liabilities or Regulatory Assets		  
            2012     2011  

Ameren(a)

    Fuel oils    $ 5      $ 29   
  

Natural gas

      (18 )      31   
  

Power

      (162 )      2   
    

Uranium

      -        (1 ) 
    

Total

    $ (175 )    $ 61   

Ameren

    Fuel oils    $ 5      $ 29   

Missouri

    Natural gas      (2 )      3   
  

Power

      (1 )      -   
    

Uranium

      -        (1 ) 
    

Total

    $ 2      $ 31   

Ameren Illinois

    Natural gas    $ (16 )    $ 28   
     Power      (144 )      27   
    

Total

    $ (160 )    $ 55   
(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. The fair value of the financial contracts included in "MTM derivative liabilities - affiliates" on Ameren Illinois' balance sheet totaled $183 million and $200 million at March 31, 2012, and December 31, 2011, respectively. See Note 14 - Related Party Transactions under Part II, Item 8, of the Form 10-K for additional information on these financial contracts.

Fair Value Measurements
Fair Value Measurements 

NOTE 7 - FAIR VALUE MEASUREMENTS

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri's Nuclear Decommissioning Trust Fund.

The market approach is used to measure the fair value of equity securities held in Ameren Missouri's Nuclear Decommissioning Trust Fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index is comprised of stocks of large capitalization companies.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri's Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, U.S. treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.

Fixed income securities are valued using prices from independent, industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the Nuclear Decommissioning Trust Fund are comprised primarily of corporate bonds, asset-backed securities and U.S. agency bonds.

Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivative contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between Ameren Illinois and Marketing Company as part of the 2007 Illinois Electric Supply Agreement. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2012:

 

            Fair Value      Valuation Technique(s)    Unobservable Input   

Range [Weighted

Average]

Level 3 Derivative assets - commodity contracts(b):

Ameren(a)

    Fuel oils    $ 9       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [1%]
  

Power(e)

      170       Option model    Volatilities(d)    15% - 68% [19%]
            Average bid/ask consensus pricing(d)    $16/MWh-$39/MWh [$35/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$29/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$173/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 13% [5%]

Ameren

Missouri

    Fuel oils    $ 7       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 4% [1%]
  

Power(e)

      28       Option model    Volatilities(d)    40% - 68% [61%]
            Average bid/ask consensus pricing(d)    $16/MWh - $31/MWh [$19/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $17/MWh - $49/MWh [$23/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$170/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 12% [5%]

Genco

    Fuel oils    $ 2       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    25% - 28% [26%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [2%]

Level 3 Derivative liabilities - commodity contracts(b):

Ameren(a)

    Power(e)    $ 194       Option model    Volatilities(d)    15% - 40% [24%]
            Average bid/ask consensus pricing(d)    $16/MWh - $39/MWh [$34/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$28/MWh]

 

            Fair Value      Valuation
Technique(s)		    Unobservable Input   

Range [Weighted

Average]

         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
         Credit risk discount    Ameren credit risk(d)    3% - 6% [6%]
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren

Missouri

    Power(e)    $ 8       Option model    Volatilities(d)    35% - 40% [37%]
            Average bid/ask consensus pricing(d)    $16/MWh - $27/MWh [$23/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$27/MWh]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Ameren Missouri credit risk(d)    3%
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren Illinois

    Power(e)    $ 284       Power forwards/swaps third party pricing    Average bid/ask consensus pricing(c)    $20/MWh - $36/MWh $[28/MWh]
         Basis to nodal valuation price    Nodal basis(d)    $(4)/MWh - $(1)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
                   Credit risk discount    Ameren Illinois credit risk(d)    6%

 

(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) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(d) Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2015. Valuations beyond 2015 utilize power market simulation modeled pricing by month for peak and off-peak.

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 and Genco recorded losses totaling $2 million and less than $1 million, respectively, in the first quarter of 2012 and gains totaling less than $1 million in the first quarter of 2011 related to valuation adjustments for counterparty default risk. At March 31, 2012, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $8 million, less than $(1) million, $22 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. At December 31, 2011, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, $19 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 March 31, 2012:

 

           

Quoted Prices in

Active Markets for
Identical Assets

or Liabilities

(Level 1)

     

Significant Other
Observable Inputs

(Level 2)

     

Significant Other

Unobservable
Inputs

(Level 3)

          Total      

Assets:

               

Ameren(a)

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

    $ 36       $ -       $ 9       $ 45   
  

Natural gas

      4         2         -         6   
  

Power

      -         15         170         185   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Missouri

   

Fuel oils

      20         -         7         27   
  

Natural gas

      2         -         -         2   
  

Power

      -         7         28         35   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Illinois

   

Natural gas

      -         1         -         1   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      11         -         2         13   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

    $ 4       $ -       $ -       $ 4   
  

Fuel oils

      1         -         -         1   
  

Natural gas

      19         196         -         215   
  

Power

      -         16         194         210   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         16         -         28   
  

Power

      -         7         8         15   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      5         179         -         184   
    

Power

      -         -         284         284   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

      3         -         -         3   
    

Natural gas

      1         -         -         1   

 

(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, 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):

            
  

Fuel oils

    $ 33       $ -       $ 4       $ 37   
  

Natural gas

      4         -         2         6   
  

Power

      -         2         193         195   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Missouri

   

Fuel oils

      20         -         3         23   
  

Natural gas

      2         -         -         2   
  

Power

      -         1         29         30   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Illinois

   

Natural gas

      -         -         2         2   
    

Power

      -         -         77         77   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      10         -         1         11   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

    $ 2       $ -       $ -       $ 2   
  

Natural gas

      22         -         176         198   
  

Power

      -         2         78         80   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         -         14         26   
  

Power

      -         1         8         9   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      7         -         162         169   
    

Power

      -         -         217         217   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

      1         -         -         1   
    

Natural gas

      2         -         -         2   

 

(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 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 March 31, 2012:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2012

    $ 3      $ (a )    $ 1      $ —        $ 4   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      2        -        2   

Included in regulatory assets/liabilities

      2        (a )      (a )      (a )      2   

Total realized and unrealized gains (losses)

      2        (a )      2        -        4   

Transfers into Level 3

      2        (a )      -        -        2   

Transfers out of Level 3

      -        (a )      (1 )      -        (1 ) 

Ending balance at March 31, 2012

    $ 7      $ (a )    $ 2      $        $ 9   

Change in unrealized gains (losses) related to assets/liabilities held at March 31,2012

    $ 2      $ (a )    $ 1      $        $ 3   

Natural gas:

           

Beginning balance at January 1, 2012

    $ (14 )    $ (160 )    $ -      $ -      $ (174 ) 

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      (2 )      (26 )      (a )      (a )      (28 ) 

Total realized and unrealized gains (losses)

      (2 )      (26 )      (a )      (a )      (28 ) 

Settlements

      1        16        -        -        17   

Transfer out of Level 3

      15        170        -        -        185   

Ending balance at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Power:

           

Beginning balance at January 1, 2012

    $ 21      $ (140 )    $ -      $ 234      $ 115   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        8        8   

Included in OCI

      -        -        -        24        24   

Included in regulatory assets/liabilities

      13        (220 )      (a )      49        (158 ) 

Total realized and unrealized gains (losses)

      13        (220 )      -        81        (126 ) 

Purchases

      -        -        -        (1 )      (1 ) 

Sales

      -        -        -        1        1   

Settlements

      (13 )      76        -        (77 )      (14 ) 

Transfers out of Level 3

      (1 )      -        -        2        1   

Ending balance at March 31, 2012

    $ 20      $ (284 )    $ -      $ 240      $ (24 ) 

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ 10      $ (202 )(d)    $ -      $ 59      $ (133 ) 

Uranium:

           

Beginning balance at January 1, 2012

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        (a )      (a )      (a )      -   

Total realized and unrealized gains (losses)

      -        (a )      (a )      (a )      -   

Ending balance at March 31, 2012

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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.
(d) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois' swap contracts, which expire in May 2032.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of March 31, 2011:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2011

    $ 30      $ (a )    $ 17      $ 4      $ 51   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      15        7        22   

Included in regulatory assets/liabilities

      31        (a )      (a )      (a )      31   

Total realized and unrealized gains (losses)

      31        (a )      15        7        53   

Purchases

      1        (a )      -        -        1   

Settlements

      (5 )      (a )      (3 )      (1 )      (9 ) 

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 49      $ (a )    $ 16      $ 4      $ 69   

Natural gas:

           

Beginning balance at January 1, 2011

    $ (14 )    $ (134 )    $ -      $ -      $ (148 ) 

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        7        (a )      (a )      7   

Total realized and unrealized gains (losses)

      -        7        -        -        7   

Settlements

      2        19        -        -        21   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 1      $ 6      $ -      $ -      $ 7   

Power:

           

Beginning balance at January 1, 2011

    $ 2      $ (352 )    $ 3      $ 383      $ 36   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        (3 )      (3 ) 

Included in OCI

      -        -        -        -        -   

Included in regulatory assets/liabilities

      7        (30 )      (a )      21        (2 ) 

Total realized and unrealized gains (losses)

      7        (30 )      -        18        (5 ) 

Purchases

      -        -        -        9        9   

Sales

      -        -        -        (9 )      (9 ) 

Settlements

      (6 )      57        -        (51 )      -   

Transfers into Level 3

      (1 )      -        -        1        -   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 3      $ (25 )    $ -      $ 31      $ 9   

Uranium:

           

Beginning balance at January 1, 2011

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

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

Total realized and unrealized gains (losses)

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

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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 in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter of 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended March 31, 2012, and the previous reporting period ended December 31, 2011. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the periods ended March 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three months ended March 31, 2012, and 2011:

 

      2012     2011  

Ameren - derivative commodity contracts:(a)

     

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

    $   2      $   - 

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

      (1 )      -   

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

      185        -   

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

      1        -   

Net fair value of Level 3 transfers

    $   187      $ -   

 

      2012     2011  

Ameren Missouri - derivative commodity contracts:

     

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

    $ 2      $ -   

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

      15        -   

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

      -        (1 ) 

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

      (1 )      -   

Net fair value of Level 3 transfers

    $ 16      $ (1 ) 

Ameren Illinois - derivative commodity contracts:

     

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

    $ 170      $ -   

Genco - derivative commodity contracts:

     

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

    $ (1 )    $ -   

 

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

The Ameren Companies' carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at March 31, 2012, and December 31, 2011:

 

      March 31, 2012      December 31, 2011  
      Carrying
Amount		      Fair
Value		      Carrying
Amount		      Fair
Value		  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,856       $   7,673       $ 6,856       $   7,800   

Preferred stock

      142         93         142         92   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,950       $ 4,530       $ 3,950       $ 4,541   

Preferred stock

      80         55         80         55   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,967       $ 1,658       $ 1,943   

Preferred stock

      62         38         62         37   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 693       $ 824       $ 839   

 

(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

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri's Nuclear Decommissioning Trust Fund.

The market approach is used to measure the fair value of equity securities held in Ameren Missouri's Nuclear Decommissioning Trust Fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index is comprised of stocks of large capitalization companies.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri's Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, U.S. treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.

Fixed income securities are valued using prices from independent, industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the Nuclear Decommissioning Trust Fund are comprised primarily of corporate bonds, asset-backed securities and U.S. agency bonds.

Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivative contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between Ameren Illinois and Marketing Company as part of the 2007 Illinois Electric Supply Agreement. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2012:

 

            Fair Value      Valuation Technique(s)    Unobservable Input   

Range [Weighted

Average]

Level 3 Derivative assets - commodity contracts(b):

Ameren(a)

    Fuel oils    $ 9       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [1%]
  

Power(e)

      170       Option model    Volatilities(d)    15% - 68% [19%]
            Average bid/ask consensus pricing(d)    $16/MWh-$39/MWh [$35/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$29/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$173/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 13% [5%]

Ameren

Missouri

    Fuel oils    $ 7       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 4% [1%]
  

Power(e)

      28       Option model    Volatilities(d)    40% - 68% [61%]
            Average bid/ask consensus pricing(d)    $16/MWh - $31/MWh [$19/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $17/MWh - $49/MWh [$23/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$170/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 12% [5%]

Genco

    Fuel oils    $ 2       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    25% - 28% [26%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [2%]

Level 3 Derivative liabilities - commodity contracts(b):

Ameren(a)

    Power(e)    $ 194       Option model    Volatilities(d)    15% - 40% [24%]
            Average bid/ask consensus pricing(d)    $16/MWh - $39/MWh [$34/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$28/MWh]

 

            Fair Value      Valuation
Technique(s)		    Unobservable Input   

Range [Weighted

Average]

         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
         Credit risk discount    Ameren credit risk(d)    3% - 6% [6%]
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren

Missouri

    Power(e)    $ 8       Option model    Volatilities(d)    35% - 40% [37%]
            Average bid/ask consensus pricing(d)    $16/MWh - $27/MWh [$23/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$27/MWh]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Ameren Missouri credit risk(d)    3%
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren Illinois

    Power(e)    $ 284       Power forwards/swaps third party pricing    Average bid/ask consensus pricing(c)    $20/MWh - $36/MWh $[28/MWh]
         Basis to nodal valuation price    Nodal basis(d)    $(4)/MWh - $(1)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
                   Credit risk discount    Ameren Illinois credit risk(d)    6%

 

(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) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(d) Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2015. Valuations beyond 2015 utilize power market simulation modeled pricing by month for peak and off-peak.

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 and Genco recorded losses totaling $2 million and less than $1 million, respectively, in the first quarter of 2012 and gains totaling less than $1 million in the first quarter of 2011 related to valuation adjustments for counterparty default risk. At March 31, 2012, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $8 million, less than $(1) million, $22 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. At December 31, 2011, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, $19 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 March 31, 2012:

 

           

Quoted Prices in

Active Markets for
Identical Assets

or Liabilities

(Level 1)

     

Significant Other
Observable Inputs

(Level 2)

     

Significant Other

Unobservable
Inputs

(Level 3)

          Total      

Assets:

               

Ameren(a)

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

    $ 36       $ -       $ 9       $ 45   
  

Natural gas

      4         2         -         6   
  

Power

      -         15         170         185   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Missouri

   

Fuel oils

      20         -         7         27   
  

Natural gas

      2         -         -         2   
  

Power

      -         7         28         35   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Illinois

   

Natural gas

      -         1         -         1   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      11         -         2         13   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

    $ 4       $ -       $ -       $ 4   
  

Fuel oils

      1         -         -         1   
  

Natural gas

      19         196         -         215   
  

Power

      -         16         194         210   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         16         -         28   
  

Power

      -         7         8         15   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      5         179         -         184   
    

Power

      -         -         284         284   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

      3         -         -         3   
    

Natural gas

      1         -         -         1   

 

(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, 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):

            
  

Fuel oils

    $ 33       $ -       $ 4       $ 37   
  

Natural gas

      4         -         2         6   
  

Power

      -         2         193         195   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Missouri

   

Fuel oils

      20         -         3         23   
  

Natural gas

      2         -         -         2   
  

Power

      -         1         29         30   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Illinois

   

Natural gas

      -         -         2         2   
    

Power

      -         -         77         77   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      10         -         1         11   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

    $ 2       $ -       $ -       $ 2   
  

Natural gas

      22         -         176         198   
  

Power

      -         2         78         80   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         -         14         26   
  

Power

      -         1         8         9   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      7         -         162         169   
    

Power

      -         -         217         217   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

      1         -         -         1   
    

Natural gas

      2         -         -         2   

 

(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 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 March 31, 2012:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2012

    $ 3      $ (a )    $ 1      $ —        $ 4   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      2        -        2   

Included in regulatory assets/liabilities

      2        (a )      (a )      (a )      2   

Total realized and unrealized gains (losses)

      2        (a )      2        -        4   

Transfers into Level 3

      2        (a )      -        -        2   

Transfers out of Level 3

      -        (a )      (1 )      -        (1 ) 

Ending balance at March 31, 2012

    $ 7      $ (a )    $ 2      $        $ 9   

Change in unrealized gains (losses) related to assets/liabilities held at March 31,2012

    $ 2      $ (a )    $ 1      $        $ 3   

Natural gas:

           

Beginning balance at January 1, 2012

    $ (14 )    $ (160 )    $ -      $ -      $ (174 ) 

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      (2 )      (26 )      (a )      (a )      (28 ) 

Total realized and unrealized gains (losses)

      (2 )      (26 )      (a )      (a )      (28 ) 

Settlements

      1        16        -        -        17   

Transfer out of Level 3

      15        170        -        -        185   

Ending balance at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Power:

           

Beginning balance at January 1, 2012

    $ 21      $ (140 )    $ -      $ 234      $ 115   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        8        8   

Included in OCI

      -        -        -        24        24   

Included in regulatory assets/liabilities

      13        (220 )      (a )      49        (158 ) 

Total realized and unrealized gains (losses)

      13        (220 )      -        81        (126 ) 

Purchases

      -        -        -        (1 )      (1 ) 

Sales

      -        -        -        1        1   

Settlements

      (13 )      76        -        (77 )      (14 ) 

Transfers out of Level 3

      (1 )      -        -        2        1   

Ending balance at March 31, 2012

    $ 20      $ (284 )    $ -      $ 240      $ (24 ) 

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ 10      $ (202 )(d)    $ -      $ 59      $ (133 ) 

Uranium:

           

Beginning balance at January 1, 2012

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        (a )      (a )      (a )      -   

Total realized and unrealized gains (losses)

      -        (a )      (a )      (a )      -   

Ending balance at March 31, 2012

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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.
(d) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois' swap contracts, which expire in May 2032.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of March 31, 2011:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2011

    $ 30      $ (a )    $ 17      $ 4      $ 51   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      15        7        22   

Included in regulatory assets/liabilities

      31        (a )      (a )      (a )      31   

Total realized and unrealized gains (losses)

      31        (a )      15        7        53   

Purchases

      1        (a )      -        -        1   

Settlements

      (5 )      (a )      (3 )      (1 )      (9 ) 

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 49      $ (a )    $ 16      $ 4      $ 69   

Natural gas:

           

Beginning balance at January 1, 2011

    $ (14 )    $ (134 )    $ -      $ -      $ (148 ) 

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        7        (a )      (a )      7   

Total realized and unrealized gains (losses)

      -        7        -        -        7   

Settlements

      2        19        -        -        21   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 1      $ 6      $ -      $ -      $ 7   

Power:

           

Beginning balance at January 1, 2011

    $ 2      $ (352 )    $ 3      $ 383      $ 36   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        (3 )      (3 ) 

Included in OCI

      -        -        -        -        -   

Included in regulatory assets/liabilities

      7        (30 )      (a )      21        (2 ) 

Total realized and unrealized gains (losses)

      7        (30 )      -        18        (5 ) 

Purchases

      -        -        -        9        9   

Sales

      -        -        -        (9 )      (9 ) 

Settlements

      (6 )      57        -        (51 )      -   

Transfers into Level 3

      (1 )      -        -        1        -   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 3      $ (25 )    $ -      $ 31      $ 9   

Uranium:

           

Beginning balance at January 1, 2011

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

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

Total realized and unrealized gains (losses)

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

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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 in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter of 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended March 31, 2012, and the previous reporting period ended December 31, 2011. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the periods ended March 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three months ended March 31, 2012, and 2011:

 

      2012     2011  

Ameren - derivative commodity contracts:(a)

     

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

    $   2      $   - 

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

      (1 )      -   

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

      185        -   

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

      1        -   

Net fair value of Level 3 transfers

    $   187      $ -   

 

      2012     2011  

Ameren Missouri - derivative commodity contracts:

     

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

    $ 2      $ -   

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

      15        -   

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

      -        (1 ) 

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

      (1 )      -   

Net fair value of Level 3 transfers

    $ 16      $ (1 ) 

Ameren Illinois - derivative commodity contracts:

     

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

    $ 170      $ -   

Genco - derivative commodity contracts:

     

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

    $ (1 )    $ -   

 

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

The Ameren Companies' carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at March 31, 2012, and December 31, 2011:

 

      March 31, 2012      December 31, 2011  
      Carrying
Amount		      Fair
Value		      Carrying
Amount		      Fair
Value		  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,856       $   7,673       $ 6,856       $   7,800   

Preferred stock

      142         93         142         92   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,950       $ 4,530       $ 3,950       $ 4,541   

Preferred stock

      80         55         80         55   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,967       $ 1,658       $ 1,943   

Preferred stock

      62         38         62         37   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 693       $ 824       $ 839   

 

(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

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri's Nuclear Decommissioning Trust Fund.

The market approach is used to measure the fair value of equity securities held in Ameren Missouri's Nuclear Decommissioning Trust Fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index is comprised of stocks of large capitalization companies.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri's Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, U.S. treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.

Fixed income securities are valued using prices from independent, industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the Nuclear Decommissioning Trust Fund are comprised primarily of corporate bonds, asset-backed securities and U.S. agency bonds.

Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivative contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between Ameren Illinois and Marketing Company as part of the 2007 Illinois Electric Supply Agreement. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2012:

 

            Fair Value      Valuation Technique(s)    Unobservable Input   

Range [Weighted

Average]

Level 3 Derivative assets - commodity contracts(b):

Ameren(a)

    Fuel oils    $ 9       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [1%]
  

Power(e)

      170       Option model    Volatilities(d)    15% - 68% [19%]
            Average bid/ask consensus pricing(d)    $16/MWh-$39/MWh [$35/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$29/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$173/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 13% [5%]

Ameren

Missouri

    Fuel oils    $ 7       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 4% [1%]
  

Power(e)

      28       Option model    Volatilities(d)    40% - 68% [61%]
            Average bid/ask consensus pricing(d)    $16/MWh - $31/MWh [$19/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $17/MWh - $49/MWh [$23/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$170/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 12% [5%]

Genco

    Fuel oils    $ 2       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    25% - 28% [26%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [2%]

Level 3 Derivative liabilities - commodity contracts(b):

Ameren(a)

    Power(e)    $ 194       Option model    Volatilities(d)    15% - 40% [24%]
            Average bid/ask consensus pricing(d)    $16/MWh - $39/MWh [$34/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$28/MWh]

 

            Fair Value      Valuation
Technique(s)		    Unobservable Input   

Range [Weighted

Average]

         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
         Credit risk discount    Ameren credit risk(d)    3% - 6% [6%]
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren

Missouri

    Power(e)    $ 8       Option model    Volatilities(d)    35% - 40% [37%]
            Average bid/ask consensus pricing(d)    $16/MWh - $27/MWh [$23/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$27/MWh]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Ameren Missouri credit risk(d)    3%
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren Illinois

    Power(e)    $ 284       Power forwards/swaps third party pricing    Average bid/ask consensus pricing(c)    $20/MWh - $36/MWh $[28/MWh]
         Basis to nodal valuation price    Nodal basis(d)    $(4)/MWh - $(1)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
                   Credit risk discount    Ameren Illinois credit risk(d)    6%

 

(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) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(d) Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2015. Valuations beyond 2015 utilize power market simulation modeled pricing by month for peak and off-peak.

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 and Genco recorded losses totaling $2 million and less than $1 million, respectively, in the first quarter of 2012 and gains totaling less than $1 million in the first quarter of 2011 related to valuation adjustments for counterparty default risk. At March 31, 2012, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $8 million, less than $(1) million, $22 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. At December 31, 2011, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, $19 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 March 31, 2012:

 

           

Quoted Prices in

Active Markets for
Identical Assets

or Liabilities

(Level 1)

     

Significant Other
Observable Inputs

(Level 2)

     

Significant Other

Unobservable
Inputs

(Level 3)

          Total      

Assets:

               

Ameren(a)

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

    $ 36       $ -       $ 9       $ 45   
  

Natural gas

      4         2         -         6   
  

Power

      -         15         170         185   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Missouri

   

Fuel oils

      20         -         7         27   
  

Natural gas

      2         -         -         2   
  

Power

      -         7         28         35   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Illinois

   

Natural gas

      -         1         -         1   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      11         -         2         13   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

    $ 4       $ -       $ -       $ 4   
  

Fuel oils

      1         -         -         1   
  

Natural gas

      19         196         -         215   
  

Power

      -         16         194         210   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         16         -         28   
  

Power

      -         7         8         15   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      5         179         -         184   
    

Power

      -         -         284         284   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

      3         -         -         3   
    

Natural gas

      1         -         -         1   

 

(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, 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):

            
  

Fuel oils

    $ 33       $ -       $ 4       $ 37   
  

Natural gas

      4         -         2         6   
  

Power

      -         2         193         195   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Missouri

   

Fuel oils

      20         -         3         23   
  

Natural gas

      2         -         -         2   
  

Power

      -         1         29         30   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Illinois

   

Natural gas

      -         -         2         2   
    

Power

      -         -         77         77   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      10         -         1         11   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

    $ 2       $ -       $ -       $ 2   
  

Natural gas

      22         -         176         198   
  

Power

      -         2         78         80   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         -         14         26   
  

Power

      -         1         8         9   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      7         -         162         169   
    

Power

      -         -         217         217   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

      1         -         -         1   
    

Natural gas

      2         -         -         2   

 

(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 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 March 31, 2012:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2012

    $ 3      $ (a )    $ 1      $ —        $ 4   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      2        -        2   

Included in regulatory assets/liabilities

      2        (a )      (a )      (a )      2   

Total realized and unrealized gains (losses)

      2        (a )      2        -        4   

Transfers into Level 3

      2        (a )      -        -        2   

Transfers out of Level 3

      -        (a )      (1 )      -        (1 ) 

Ending balance at March 31, 2012

    $ 7      $ (a )    $ 2      $        $ 9   

Change in unrealized gains (losses) related to assets/liabilities held at March 31,2012

    $ 2      $ (a )    $ 1      $        $ 3   

Natural gas:

           

Beginning balance at January 1, 2012

    $ (14 )    $ (160 )    $ -      $ -      $ (174 ) 

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      (2 )      (26 )      (a )      (a )      (28 ) 

Total realized and unrealized gains (losses)

      (2 )      (26 )      (a )      (a )      (28 ) 

Settlements

      1        16        -        -        17   

Transfer out of Level 3

      15        170        -        -        185   

Ending balance at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Power:

           

Beginning balance at January 1, 2012

    $ 21      $ (140 )    $ -      $ 234      $ 115   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        8        8   

Included in OCI

      -        -        -        24        24   

Included in regulatory assets/liabilities

      13        (220 )      (a )      49        (158 ) 

Total realized and unrealized gains (losses)

      13        (220 )      -        81        (126 ) 

Purchases

      -        -        -        (1 )      (1 ) 

Sales

      -        -        -        1        1   

Settlements

      (13 )      76        -        (77 )      (14 ) 

Transfers out of Level 3

      (1 )      -        -        2        1   

Ending balance at March 31, 2012

    $ 20      $ (284 )    $ -      $ 240      $ (24 ) 

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ 10      $ (202 )(d)    $ -      $ 59      $ (133 ) 

Uranium:

           

Beginning balance at January 1, 2012

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        (a )      (a )      (a )      -   

Total realized and unrealized gains (losses)

      -        (a )      (a )      (a )      -   

Ending balance at March 31, 2012

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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.
(d) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois' swap contracts, which expire in May 2032.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of March 31, 2011:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2011

    $ 30      $ (a )    $ 17      $ 4      $ 51   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      15        7        22   

Included in regulatory assets/liabilities

      31        (a )      (a )      (a )      31   

Total realized and unrealized gains (losses)

      31        (a )      15        7        53   

Purchases

      1        (a )      -        -        1   

Settlements

      (5 )      (a )      (3 )      (1 )      (9 ) 

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 49      $ (a )    $ 16      $ 4      $ 69   

Natural gas:

           

Beginning balance at January 1, 2011

    $ (14 )    $ (134 )    $ -      $ -      $ (148 ) 

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        7        (a )      (a )      7   

Total realized and unrealized gains (losses)

      -        7        -        -        7   

Settlements

      2        19        -        -        21   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 1      $ 6      $ -      $ -      $ 7   

Power:

           

Beginning balance at January 1, 2011

    $ 2      $ (352 )    $ 3      $ 383      $ 36   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        (3 )      (3 ) 

Included in OCI

      -        -        -        -        -   

Included in regulatory assets/liabilities

      7        (30 )      (a )      21        (2 ) 

Total realized and unrealized gains (losses)

      7        (30 )      -        18        (5 ) 

Purchases

      -        -        -        9        9   

Sales

      -        -        -        (9 )      (9 ) 

Settlements

      (6 )      57        -        (51 )      -   

Transfers into Level 3

      (1 )      -        -        1        -   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 3      $ (25 )    $ -      $ 31      $ 9   

Uranium:

           

Beginning balance at January 1, 2011

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

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

Total realized and unrealized gains (losses)

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

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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 in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter of 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended March 31, 2012, and the previous reporting period ended December 31, 2011. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the periods ended March 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three months ended March 31, 2012, and 2011:

 

      2012     2011  

Ameren - derivative commodity contracts:(a)

     

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

    $   2      $   - 

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

      (1 )      -   

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

      185        -   

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

      1        -   

Net fair value of Level 3 transfers

    $   187      $ -   

 

      2012     2011  

Ameren Missouri - derivative commodity contracts:

     

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

    $ 2      $ -   

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

      15        -   

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

      -        (1 ) 

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

      (1 )      -   

Net fair value of Level 3 transfers

    $ 16      $ (1 ) 

Ameren Illinois - derivative commodity contracts:

     

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

    $ 170      $ -   

Genco - derivative commodity contracts:

     

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

    $ (1 )    $ -   

 

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

The Ameren Companies' carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at March 31, 2012, and December 31, 2011:

 

      March 31, 2012      December 31, 2011  
      Carrying
Amount		      Fair
Value		      Carrying
Amount		      Fair
Value		  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,856       $   7,673       $ 6,856       $   7,800   

Preferred stock

      142         93         142         92   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,950       $ 4,530       $ 3,950       $ 4,541   

Preferred stock

      80         55         80         55   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,967       $ 1,658       $ 1,943   

Preferred stock

      62         38         62         37   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 693       $ 824       $ 839   

 

(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

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri's Nuclear Decommissioning Trust Fund.

The market approach is used to measure the fair value of equity securities held in Ameren Missouri's Nuclear Decommissioning Trust Fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index is comprised of stocks of large capitalization companies.

Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri's Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, U.S. treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions.

Fixed income securities are valued using prices from independent, industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the Nuclear Decommissioning Trust Fund are comprised primarily of corporate bonds, asset-backed securities and U.S. agency bonds.

Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivative contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments.

Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between Ameren Illinois and Marketing Company as part of the 2007 Illinois Electric Supply Agreement. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2012:

 

            Fair Value      Valuation Technique(s)    Unobservable Input   

Range [Weighted

Average]

Level 3 Derivative assets - commodity contracts(b):

Ameren(a)

    Fuel oils    $ 9       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [1%]
  

Power(e)

      170       Option model    Volatilities(d)    15% - 68% [19%]
            Average bid/ask consensus pricing(d)    $16/MWh-$39/MWh [$35/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$29/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$173/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 13% [5%]

Ameren

Missouri

    Fuel oils    $ 7       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 4% [1%]
  

Power(e)

      28       Option model    Volatilities(d)    40% - 68% [61%]
            Average bid/ask consensus pricing(d)    $16/MWh - $31/MWh [$19/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $17/MWh - $49/MWh [$23/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$170/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 12% [5%]

Genco

    Fuel oils    $ 2       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    25% - 28% [26%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [2%]

Level 3 Derivative liabilities - commodity contracts(b):

Ameren(a)

    Power(e)    $ 194       Option model    Volatilities(d)    15% - 40% [24%]
            Average bid/ask consensus pricing(d)    $16/MWh - $39/MWh [$34/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$28/MWh]

 

            Fair Value      Valuation
Technique(s)		    Unobservable Input   

Range [Weighted

Average]

         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
         Credit risk discount    Ameren credit risk(d)    3% - 6% [6%]
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren

Missouri

    Power(e)    $ 8       Option model    Volatilities(d)    35% - 40% [37%]
            Average bid/ask consensus pricing(d)    $16/MWh - $27/MWh [$23/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$27/MWh]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Ameren Missouri credit risk(d)    3%
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren Illinois

    Power(e)    $ 284       Power forwards/swaps third party pricing    Average bid/ask consensus pricing(c)    $20/MWh - $36/MWh $[28/MWh]
         Basis to nodal valuation price    Nodal basis(d)    $(4)/MWh - $(1)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
                   Credit risk discount    Ameren Illinois credit risk(d)    6%

 

(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) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(d) Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2015. Valuations beyond 2015 utilize power market simulation modeled pricing by month for peak and off-peak.

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 and Genco recorded losses totaling $2 million and less than $1 million, respectively, in the first quarter of 2012 and gains totaling less than $1 million in the first quarter of 2011 related to valuation adjustments for counterparty default risk. At March 31, 2012, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $8 million, less than $(1) million, $22 million, and less than $(1) million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. At December 31, 2011, the counterparty default risk (asset)/liability valuation adjustment related to derivative contracts totaled $1 million, less than $1 million, $19 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 March 31, 2012:

 

           

Quoted Prices in

Active Markets for
Identical Assets

or Liabilities

(Level 1)

     

Significant Other
Observable Inputs

(Level 2)

     

Significant Other

Unobservable
Inputs

(Level 3)

          Total      

Assets:

               

Ameren(a)

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

    $ 36       $ -       $ 9       $ 45   
  

Natural gas

      4         2         -         6   
  

Power

      -         15         170         185   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Missouri

   

Fuel oils

      20         -         7         27   
  

Natural gas

      2         -         -         2   
  

Power

      -         7         28         35   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Illinois

   

Natural gas

      -         1         -         1   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      11         -         2         13   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

    $ 4       $ -       $ -       $ 4   
  

Fuel oils

      1         -         -         1   
  

Natural gas

      19         196         -         215   
  

Power

      -         16         194         210   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         16         -         28   
  

Power

      -         7         8         15   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      5         179         -         184   
    

Power

      -         -         284         284   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

      3         -         -         3   
    

Natural gas

      1         -         -         1   

 

(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, 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):

            
  

Fuel oils

    $ 33       $ -       $ 4       $ 37   
  

Natural gas

      4         -         2         6   
  

Power

      -         2         193         195   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Missouri

   

Fuel oils

      20         -         3         23   
  

Natural gas

      2         -         -         2   
  

Power

      -         1         29         30   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Illinois

   

Natural gas

      -         -         2         2   
    

Power

      -         -         77         77   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      10         -         1         11   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

    $ 2       $ -       $ -       $ 2   
  

Natural gas

      22         -         176         198   
  

Power

      -         2         78         80   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         -         14         26   
  

Power

      -         1         8         9   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      7         -         162         169   
    

Power

      -         -         217         217   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

      1         -         -         1   
    

Natural gas

      2         -         -         2   

 

(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 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 March 31, 2012:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2012

    $ 3      $ (a )    $ 1      $ —        $ 4   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      2        -        2   

Included in regulatory assets/liabilities

      2        (a )      (a )      (a )      2   

Total realized and unrealized gains (losses)

      2        (a )      2        -        4   

Transfers into Level 3

      2        (a )      -        -        2   

Transfers out of Level 3

      -        (a )      (1 )      -        (1 ) 

Ending balance at March 31, 2012

    $ 7      $ (a )    $ 2      $        $ 9   

Change in unrealized gains (losses) related to assets/liabilities held at March 31,2012

    $ 2      $ (a )    $ 1      $        $ 3   

Natural gas:

           

Beginning balance at January 1, 2012

    $ (14 )    $ (160 )    $ -      $ -      $ (174 ) 

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      (2 )      (26 )      (a )      (a )      (28 ) 

Total realized and unrealized gains (losses)

      (2 )      (26 )      (a )      (a )      (28 ) 

Settlements

      1        16        -        -        17   

Transfer out of Level 3

      15        170        -        -        185   

Ending balance at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Power:

           

Beginning balance at January 1, 2012

    $ 21      $ (140 )    $ -      $ 234      $ 115   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        8        8   

Included in OCI

      -        -        -        24        24   

Included in regulatory assets/liabilities

      13        (220 )      (a )      49        (158 ) 

Total realized and unrealized gains (losses)

      13        (220 )      -        81        (126 ) 

Purchases

      -        -        -        (1 )      (1 ) 

Sales

      -        -        -        1        1   

Settlements

      (13 )      76        -        (77 )      (14 ) 

Transfers out of Level 3

      (1 )      -        -        2        1   

Ending balance at March 31, 2012

    $ 20      $ (284 )    $ -      $ 240      $ (24 ) 

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ 10      $ (202 )(d)    $ -      $ 59      $ (133 ) 

Uranium:

           

Beginning balance at January 1, 2012

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        (a )      (a )      (a )      -   

Total realized and unrealized gains (losses)

      -        (a )      (a )      (a )      -   

Ending balance at March 31, 2012

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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.
(d) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois' swap contracts, which expire in May 2032.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of March 31, 2011:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2011

    $ 30      $ (a )    $ 17      $ 4      $ 51   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      15        7        22   

Included in regulatory assets/liabilities

      31        (a )      (a )      (a )      31   

Total realized and unrealized gains (losses)

      31        (a )      15        7        53   

Purchases

      1        (a )      -        -        1   

Settlements

      (5 )      (a )      (3 )      (1 )      (9 ) 

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 49      $ (a )    $ 16      $ 4      $ 69   

Natural gas:

           

Beginning balance at January 1, 2011

    $ (14 )    $ (134 )    $ -      $ -      $ (148 ) 

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        7        (a )      (a )      7   

Total realized and unrealized gains (losses)

      -        7        -        -        7   

Settlements

      2        19        -        -        21   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 1      $ 6      $ -      $ -      $ 7   

Power:

           

Beginning balance at January 1, 2011

    $ 2      $ (352 )    $ 3      $ 383      $ 36   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        (3 )      (3 ) 

Included in OCI

      -        -        -        -        -   

Included in regulatory assets/liabilities

      7        (30 )      (a )      21        (2 ) 

Total realized and unrealized gains (losses)

      7        (30 )      -        18        (5 ) 

Purchases

      -        -        -        9        9   

Sales

      -        -        -        (9 )      (9 ) 

Settlements

      (6 )      57        -        (51 )      -   

Transfers into Level 3

      (1 )      -        -        1        -   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 3      $ (25 )    $ -      $ 31      $ 9   

Uranium:

           

Beginning balance at January 1, 2011

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

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

Total realized and unrealized gains (losses)

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

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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 in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter of 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended March 31, 2012, and the previous reporting period ended December 31, 2011. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the periods ended March 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the three months ended March 31, 2012, and 2011:

 

      2012     2011  

Ameren - derivative commodity contracts:(a)

     

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

    $   2      $   - 

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

      (1 )      -   

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

      185        -   

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

      1        -   

Net fair value of Level 3 transfers

    $   187      $ -   

 

      2012     2011  

Ameren Missouri - derivative commodity contracts:

     

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

    $ 2      $ -   

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

      15        -   

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

      -        (1 ) 

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

      (1 )      -   

Net fair value of Level 3 transfers

    $ 16      $ (1 ) 

Ameren Illinois - derivative commodity contracts:

     

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

    $ 170      $ -   

Genco - derivative commodity contracts:

     

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

    $ (1 )    $ -   

 

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

The Ameren Companies' carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and estimated fair values of our long-term debt and capital lease obligations and preferred stock at March 31, 2012, and December 31, 2011:

 

      March 31, 2012      December 31, 2011  
      Carrying
Amount		      Fair
Value		      Carrying
Amount		      Fair
Value		  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,856       $   7,673       $ 6,856       $   7,800   

Preferred stock

      142         93         142         92   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,950       $ 4,530       $ 3,950       $ 4,541   

Preferred stock

      80         55         80         55   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,967       $ 1,658       $ 1,943   

Preferred stock

      62         38         62         37   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 693       $ 824       $ 839   

 

(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
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.

Put Option Agreement and Guaranty

On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gives Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin energy centers. If Genco exercises the put option, the purchase price for all three energy centers will be the greater of $100 million or the fair market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to Genco within one business day. Genco may exercise the put option at any time from March 28, 2012 through March 28, 2014. The put option may be extended indefinitely for additional one-year periods by agreement of AERG and Genco. If Genco exercises the put option, the closing of the sale of all three energy centers will be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million. The put option premium paid by Genco is reflected on Genco's March 31, 2012 consolidated balance sheet as an "Other asset" and will be amortized over two years. The amortization expense will be eliminated in the consolidation of Ameren's financial statements.

 

The put option agreement requires AERG to secure and maintain an Ameren guaranty of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guaranty agreement on March 28, 2012. AERG's primary source of financing is the non-state-regulated subsidiary money pool. If Genco exercises its put option, AERG would request a borrowing from the non-state-regulated subsidiary money pool to fund amounts due to Genco under the put option agreement. However, borrowings from the money pool are subject to Ameren control, and Ameren would consider AERG's borrowing request based on the facts and circumstances existing at that time. If Ameren decided not to provide AERG with a non-state-regulated subsidiary money pool loan necessary to fund AERG's obligations under the put option agreement, Ameren would fulfill AERG's payment obligations directly in accordance with the terms of the guaranty agreement. Therefore, the Ameren guaranty ensures the payment of all sums that may be owed by AERG to Genco under the terms of the put option agreement. The guaranty shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or the put option agreement is terminated and no further payments are owed by AERG to Genco. As of March 31, 2012, Genco had not exercised the put option and thus Ameren had no exposure to this intercompany guaranty.

Electric Power Supply Agreements

During the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Both Marketing Company and Ameren Missouri were among the winning suppliers in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively. In April 2012, Ameren Missouri contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for $1 million and $3 million for the 12 months ending May 31, 2014 and 2015, respectively. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Collateral Postings

Under the terms of the Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of December 31, 2011 and March 31, 2012, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.

Money Pools

See Note 3 - Short-term Debt 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 months ended March 31, 2012, and 2011. 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 - Short-term Debt and Liquidity of this report.

 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		     Ameren
Illinois		         Genco      

Genco and EEI power supply

    Operating Revenues      2012       $ (a )    $ (a )    $ 192   

agreements with Marketing Company

           2011         (a )      (a )      239   

Ameren Missouri and Ameren Illinois

    Operating Revenues      2012         4        (b )      (a ) 

rent and facility services

           2011         4        (b )      (a ) 

Ameren Missouri and Genco gas

    Operating Revenues      2012         (b )      (a )      (b ) 

transportation agreement

           2011         (b )      (a )      (b ) 

Total Operating Revenues

         2012       $ 4      $ (b )    $ 192   
            2011         4        (b )      239   

Ameren Illinois power supply agreements

    Purchased Power      2012       $ (a )    $ 87      $ (a ) 

with Marketing Company

           2011         (a )      46        (a ) 

EEI power supply agreement with

    Purchased Power      2012         (a )      (a )      (b ) 

Marketing Company

           2011         (a )      (a )      -   

Total Purchased Power

         2012       $ (a )    $ 87      $ (b ) 
            2011         (a )      46        -   

Ameren Services support services agreement

    Other Operations and Maintenance      2012       $ 28      $ 23      $ 5   
            2011         31        23        5   

Insurance premiums(c)

    Other Operations and Maintenance      2012         (b )      (a )      (a ) 
            2011         (b )      (a )      (a ) 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		      Ameren
Illinois		     Genco  

Total Other Operations and

         2012       $ 28       $ 23      $ 5   

Maintenance Expenses

           2011         31         23        5   

Money pool borrowings (advances)

    Interest Charges      2012       $ -       $ (b )    $ (b ) 
            2011         -         -        (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.

Put Option Agreement and Guaranty

On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gives Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin energy centers. If Genco exercises the put option, the purchase price for all three energy centers will be the greater of $100 million or the fair market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to Genco within one business day. Genco may exercise the put option at any time from March 28, 2012 through March 28, 2014. The put option may be extended indefinitely for additional one-year periods by agreement of AERG and Genco. If Genco exercises the put option, the closing of the sale of all three energy centers will be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million. The put option premium paid by Genco is reflected on Genco's March 31, 2012 consolidated balance sheet as an "Other asset" and will be amortized over two years. The amortization expense will be eliminated in the consolidation of Ameren's financial statements.

 

The put option agreement requires AERG to secure and maintain an Ameren guaranty of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guaranty agreement on March 28, 2012. AERG's primary source of financing is the non-state-regulated subsidiary money pool. If Genco exercises its put option, AERG would request a borrowing from the non-state-regulated subsidiary money pool to fund amounts due to Genco under the put option agreement. However, borrowings from the money pool are subject to Ameren control, and Ameren would consider AERG's borrowing request based on the facts and circumstances existing at that time. If Ameren decided not to provide AERG with a non-state-regulated subsidiary money pool loan necessary to fund AERG's obligations under the put option agreement, Ameren would fulfill AERG's payment obligations directly in accordance with the terms of the guaranty agreement. Therefore, the Ameren guaranty ensures the payment of all sums that may be owed by AERG to Genco under the terms of the put option agreement. The guaranty shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or the put option agreement is terminated and no further payments are owed by AERG to Genco. As of March 31, 2012, Genco had not exercised the put option and thus Ameren had no exposure to this intercompany guaranty.

Electric Power Supply Agreements

During the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Both Marketing Company and Ameren Missouri were among the winning suppliers in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively. In April 2012, Ameren Missouri contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for $1 million and $3 million for the 12 months ending May 31, 2014 and 2015, respectively. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Collateral Postings

Under the terms of the Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of December 31, 2011 and March 31, 2012, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.

Money Pools

See Note 3 - Short-term Debt 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 months ended March 31, 2012, and 2011. 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 - Short-term Debt and Liquidity of this report.

 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		     Ameren
Illinois		         Genco      

Genco and EEI power supply

    Operating Revenues      2012       $ (a )    $ (a )    $ 192   

agreements with Marketing Company

           2011         (a )      (a )      239   

Ameren Missouri and Ameren Illinois

    Operating Revenues      2012         4        (b )      (a ) 

rent and facility services

           2011         4        (b )      (a ) 

Ameren Missouri and Genco gas

    Operating Revenues      2012         (b )      (a )      (b ) 

transportation agreement

           2011         (b )      (a )      (b ) 

Total Operating Revenues

         2012       $ 4      $ (b )    $ 192   
            2011         4        (b )      239   

Ameren Illinois power supply agreements

    Purchased Power      2012       $ (a )    $ 87      $ (a ) 

with Marketing Company

           2011         (a )      46        (a ) 

EEI power supply agreement with

    Purchased Power      2012         (a )      (a )      (b ) 

Marketing Company

           2011         (a )      (a )      -   

Total Purchased Power

         2012       $ (a )    $ 87      $ (b ) 
            2011         (a )      46        -   

Ameren Services support services agreement

    Other Operations and Maintenance      2012       $ 28      $ 23      $ 5   
            2011         31        23        5   

Insurance premiums(c)

    Other Operations and Maintenance      2012         (b )      (a )      (a ) 
            2011         (b )      (a )      (a ) 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		      Ameren
Illinois		     Genco  

Total Other Operations and

         2012       $ 28       $ 23      $ 5   

Maintenance Expenses

           2011         31         23        5   

Money pool borrowings (advances)

    Interest Charges      2012       $ -       $ (b )    $ (b ) 
            2011         -         -        (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.

Put Option Agreement and Guaranty

On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gives Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin energy centers. If Genco exercises the put option, the purchase price for all three energy centers will be the greater of $100 million or the fair market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to Genco within one business day. Genco may exercise the put option at any time from March 28, 2012 through March 28, 2014. The put option may be extended indefinitely for additional one-year periods by agreement of AERG and Genco. If Genco exercises the put option, the closing of the sale of all three energy centers will be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million. The put option premium paid by Genco is reflected on Genco's March 31, 2012 consolidated balance sheet as an "Other asset" and will be amortized over two years. The amortization expense will be eliminated in the consolidation of Ameren's financial statements.

 

The put option agreement requires AERG to secure and maintain an Ameren guaranty of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guaranty agreement on March 28, 2012. AERG's primary source of financing is the non-state-regulated subsidiary money pool. If Genco exercises its put option, AERG would request a borrowing from the non-state-regulated subsidiary money pool to fund amounts due to Genco under the put option agreement. However, borrowings from the money pool are subject to Ameren control, and Ameren would consider AERG's borrowing request based on the facts and circumstances existing at that time. If Ameren decided not to provide AERG with a non-state-regulated subsidiary money pool loan necessary to fund AERG's obligations under the put option agreement, Ameren would fulfill AERG's payment obligations directly in accordance with the terms of the guaranty agreement. Therefore, the Ameren guaranty ensures the payment of all sums that may be owed by AERG to Genco under the terms of the put option agreement. The guaranty shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or the put option agreement is terminated and no further payments are owed by AERG to Genco. As of March 31, 2012, Genco had not exercised the put option and thus Ameren had no exposure to this intercompany guaranty.

Electric Power Supply Agreements

During the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Both Marketing Company and Ameren Missouri were among the winning suppliers in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively. In April 2012, Ameren Missouri contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for $1 million and $3 million for the 12 months ending May 31, 2014 and 2015, respectively. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Collateral Postings

Under the terms of the Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of December 31, 2011 and March 31, 2012, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.

Money Pools

See Note 3 - Short-term Debt 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 months ended March 31, 2012, and 2011. 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 - Short-term Debt and Liquidity of this report.

 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		     Ameren
Illinois		         Genco      

Genco and EEI power supply

    Operating Revenues      2012       $ (a )    $ (a )    $ 192   

agreements with Marketing Company

           2011         (a )      (a )      239   

Ameren Missouri and Ameren Illinois

    Operating Revenues      2012         4        (b )      (a ) 

rent and facility services

           2011         4        (b )      (a ) 

Ameren Missouri and Genco gas

    Operating Revenues      2012         (b )      (a )      (b ) 

transportation agreement

           2011         (b )      (a )      (b ) 

Total Operating Revenues

         2012       $ 4      $ (b )    $ 192   
            2011         4        (b )      239   

Ameren Illinois power supply agreements

    Purchased Power      2012       $ (a )    $ 87      $ (a ) 

with Marketing Company

           2011         (a )      46        (a ) 

EEI power supply agreement with

    Purchased Power      2012         (a )      (a )      (b ) 

Marketing Company

           2011         (a )      (a )      -   

Total Purchased Power

         2012       $ (a )    $ 87      $ (b ) 
            2011         (a )      46        -   

Ameren Services support services agreement

    Other Operations and Maintenance      2012       $ 28      $ 23      $ 5   
            2011         31        23        5   

Insurance premiums(c)

    Other Operations and Maintenance      2012         (b )      (a )      (a ) 
            2011         (b )      (a )      (a ) 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		      Ameren
Illinois		     Genco  

Total Other Operations and

         2012       $ 28       $ 23      $ 5   

Maintenance Expenses

           2011         31         23        5   

Money pool borrowings (advances)

    Interest Charges      2012       $ -       $ (b )    $ (b ) 
            2011         -         -        (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.

Put Option Agreement and Guaranty

On March 28, 2012, Genco entered into a put option agreement with AERG. The put option gives Genco the option to sell to AERG all, but not less than all, of the Grand Tower, the Gibson City, and the Elgin energy centers. If Genco exercises the put option, the purchase price for all three energy centers will be the greater of $100 million or the fair market value of the energy centers, as determined by three third-party appraisers in accordance with the terms of the agreement. Upon exercise of the put option, the $100 million minimum purchase price would be payable to Genco within one business day. Genco may exercise the put option at any time from March 28, 2012 through March 28, 2014. The put option may be extended indefinitely for additional one-year periods by agreement of AERG and Genco. If Genco exercises the put option, the closing of the sale of all three energy centers will be subject to the receipt of all necessary regulatory approvals. In exchange for entering into the put option agreement, Genco paid AERG a put option premium of $2.5 million. The put option premium paid by Genco is reflected on Genco's March 31, 2012 consolidated balance sheet as an "Other asset" and will be amortized over two years. The amortization expense will be eliminated in the consolidation of Ameren's financial statements.

 

The put option agreement requires AERG to secure and maintain an Ameren guaranty of payment of contingent obligations under the agreement. Ameren and AERG entered into such a guaranty agreement on March 28, 2012. AERG's primary source of financing is the non-state-regulated subsidiary money pool. If Genco exercises its put option, AERG would request a borrowing from the non-state-regulated subsidiary money pool to fund amounts due to Genco under the put option agreement. However, borrowings from the money pool are subject to Ameren control, and Ameren would consider AERG's borrowing request based on the facts and circumstances existing at that time. If Ameren decided not to provide AERG with a non-state-regulated subsidiary money pool loan necessary to fund AERG's obligations under the put option agreement, Ameren would fulfill AERG's payment obligations directly in accordance with the terms of the guaranty agreement. Therefore, the Ameren guaranty ensures the payment of all sums that may be owed by AERG to Genco under the terms of the put option agreement. The guaranty shall remain in effect until either AERG or Ameren satisfies all of the payment obligations under the put option agreement, or the put option agreement is terminated and no further payments are owed by AERG to Genco. As of March 31, 2012, Genco had not exercised the put option and thus Ameren had no exposure to this intercompany guaranty.

Electric Power Supply Agreements

During the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Both Marketing Company and Ameren Missouri were among the winning suppliers in the capacity RFP process. In April 2012, Marketing Company contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for less than $1 million and $4 million for the 12 months ending May 31, 2013 and 2015, respectively. In April 2012, Ameren Missouri contracted to supply a portion of Ameren Illinois' capacity requirements to Ameren Illinois for $1 million and $3 million for the 12 months ending May 31, 2014 and 2015, respectively. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Collateral Postings

Under the terms of the Illinois power procurement agreements entered into through a RFP process administered by the IPA, suppliers must post collateral under certain market conditions to protect Ameren Illinois in the event of nonperformance. The collateral postings are unilateral, meaning that only the suppliers would be required to post collateral. Therefore, Ameren Missouri, as a winning supplier of capacity, and Marketing Company, as a winning supplier of capacity and financial energy swaps, may be required to post collateral. As of December 31, 2011 and March 31, 2012, there were no collateral postings required of Ameren Missouri or Marketing Company related to the Illinois power procurement agreements.

Money Pools

See Note 3 - Short-term Debt 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 months ended March 31, 2012, and 2011. 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 - Short-term Debt and Liquidity of this report.

 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		     Ameren
Illinois		         Genco      

Genco and EEI power supply

    Operating Revenues      2012       $ (a )    $ (a )    $ 192   

agreements with Marketing Company

           2011         (a )      (a )      239   

Ameren Missouri and Ameren Illinois

    Operating Revenues      2012         4        (b )      (a ) 

rent and facility services

           2011         4        (b )      (a ) 

Ameren Missouri and Genco gas

    Operating Revenues      2012         (b )      (a )      (b ) 

transportation agreement

           2011         (b )      (a )      (b ) 

Total Operating Revenues

         2012       $ 4      $ (b )    $ 192   
            2011         4        (b )      239   

Ameren Illinois power supply agreements

    Purchased Power      2012       $ (a )    $ 87      $ (a ) 

with Marketing Company

           2011         (a )      46        (a ) 

EEI power supply agreement with

    Purchased Power      2012         (a )      (a )      (b ) 

Marketing Company

           2011         (a )      (a )      -   

Total Purchased Power

         2012       $ (a )    $ 87      $ (b ) 
            2011         (a )      46        -   

Ameren Services support services agreement

    Other Operations and Maintenance      2012       $ 28      $ 23      $ 5   
            2011         31        23        5   

Insurance premiums(c)

    Other Operations and Maintenance      2012         (b )      (a )      (a ) 
            2011         (b )      (a )      (a ) 

                    Three Months  
Agreement    Income Statement Line Item            Ameren
Missouri		      Ameren
Illinois		     Genco  

Total Other Operations and

         2012       $ 28       $ 23      $ 5   

Maintenance Expenses

           2011         31         23        5   

Money pool borrowings (advances)

    Interest Charges      2012       $ -       $ (b )    $ (b ) 
            2011         -         -        (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
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 Nuclear Plant in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at March 31, 2012. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages    

Maximum Assessments

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 industrywide 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 industrywide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We have also entered into various long-term commitments for purchased power and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Ameren Illinois contracted to purchase approximately 48,000 MWs of capacity for approximately $15 million during this period. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations, including the Illinois MPS that applies to our energy centers in Illinois, 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 proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for SO2 and NO2 emissions; the CSAPR, which requires further reductions of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; the MATS, which requires reduction of emissions of mercury, toxic 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. The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new regulations may be litigated, so the timing of their implementation is uncertain, as evidenced by the stay of the CSAPR by the United States Court of Appeals for the District of Columbia on December 30, 2011. 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. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our assessment of the potential impacts of the EPA's proposed regulation for CCR, the recently finalized MATS, the stayed CSAPR as currently designed, and the revised national ambient air quality standards for SO2 and NOx emissions as of March 31, 2012. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon a variety of factors including:

 

•  

additional federal or state requirements;

 

•  

regulation of greenhouse gas emissions;

 

•  

whether AER is granted a variance to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020;

 

•  

new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;

 

•  

additional rules governing air pollutant transport;

 

•  

finalized regulations under the Clean Water Act;

 

•  

CCR being classified as hazardous;

 

•  

whether the CSAPR is implemented and whether any modifications are made to its existing requirements;

 

•  

new technology;

 

•  

expected power prices;

 

•  

variations in costs of material or labor; and

 

•  

alternative compliance strategies or investment decisions.

 

      2012      2013 - 2016      2017 - 2021      Total  

AMO(a)

    $ 55       $ 325         -       $ 400       $
845
         -       $ 1,030       $ 1,225         -       $ 1,485   

Genco

      150         100         -         125         245         -         295         495         -         570   

AERG

      5         20         -         25         80         -         100         105         -         130   

Ameren

    $     210       $     445         -       $     550       $     1,170         -       $   1,425       $   1,825         -       $   2,185   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The decision to make pollution control equipment investments at our Merchant Generation business depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in the current year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. These scrubbers were originally expected to be installed in late 2013 and early 2014. The ultimate installation of these scrubbers, now estimated to occur between 2017 and 2021 in the table above, has been postponed until such time as the incremental investment necessary for completion is justified by visible market conditions. However, Genco will continue to incur capital costs related to the construction of these scrubbers. The table above includes Genco's estimated costs of approximately $150 million in 2012 and approximately $20 million annually, excluding capitalized interest, from 2013 through 2016 for the construction of the two scrubbers. In addition to Genco's reduction in estimated capital expenditures, AERG deferred precipitator upgrades at its E.D. Edwards energy center beyond 2016. Based on current environmental rules and regulations, if Merchant Generation and Genco do not complete these environmental upgrades by the beginning of 2015, Merchant Generation and Genco may need to reduce generation output at their energy centers to meet applicable emissions requirements. To achieve flexibility in its efforts to comply with the MPS by 2015, AER filed a request for a variance with the Illinois Pollution Control Board to extend certain compliance dates as discussed in more detail below.

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.

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 was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions. 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 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 were required in two phases beginning in 2012, with further reductions in 2014. 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, in the SO2 program, in the annual NOx, or in ozone season NOx program. Multiple legal challenges were filed requesting to have CSAPR partially or entirely vacated and to stay the implementation of the CSAPR while the court considers the challenges. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. The stay does not invalidate the rule, but only delays its implementation until a final court ruling is issued. The United States Court of Appeals for the District of Columbia has expedited its consideration of the regulation. The ultimate outcome of the challenges to the regulation is uncertain. The court could uphold CSAPR or remand it back to the EPA for partial or entire revision. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR.

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and they will require continuous monitoring systems that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be averaged for the entire power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2. It also announced plans for further reductions in the annual national ambient air quality standards for fine particulates. In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard again in 2013. The state of Illinois and the state of Missouri will be required to develop separate 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.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren Missouri's energy centers have historically burned, which will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next 10 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 additional emission reductions required by 2014 under the CSAPR, if ultimately enacted, the MATS, and other recently finalized or proposed EPA regulations.

Genco and AERG expect to install additional, or optimize existing, pollution control equipment, or modify or cease energy center operations to meet new and incremental emission reduction requirements under the MPS, the MATS, and the CSAPR as they become effective. Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. In May 2012, AER filed a request for a variance with the Illinois Pollution Control Board to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020. In exchange for delaying compliance with these emission levels through 2020, AER has proposed a plan that restricts its SO2 emissions through 2014 to levels lower than those required by the existing MPS, offsetting any environmental impact from the variance. AER has indicated to the Illinois Pollution Control Board that if a variance is not granted, or power prices do not materially increase, there is a significant risk that the Merchant Generation segment will have to mothball some of its unscrubbed coal-fired energy centers beginning in 2015. AER expects a decision from the Illinois Pollution Control Board by the end of 2012. To comply with the existing MPS and other air emissions laws and regulations, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NOx, and SO2. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco's Newton energy center. As discussed above, the timing of the installation of these scrubbers, as well as precipitator upgrades at AERG's E.D. Edwards energy center, have been delayed. Merchant Generation and Genco will continue to review and adjust their compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, environmental standards and compliance technologies, among other factors.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized 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, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, the CAIR, and 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. As noted above, on December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR including its allowance program.

Environmental regulations including the CAIR and the 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 uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. The CSAPR, however, did not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA issued a new type of emissions allowance for each program under the CSAPR. Any unused SO2 allowances, annual NOx allowances, and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco expect to have adequate CAIR allowances for 2012 to avoid needing to make external purchases.

Ameren, Ameren Missouri and Genco are studying their compliance options to identify additional opportunities that may exist for compliance in an economical fashion should the CSAPR become effective as issued. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, to install new or optimize existing pollution control equipment, to limit generation, or take other actions to achieve compliance with the CSAPR in future phase-in years.

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. The enactment of a climate change law could result in a significant rise in 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 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, economywide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.

In December 2009, the EPA issued its "endangerment finding" under the Clean Air Act which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized the "Tailoring Rule," that established new higher thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. Legal challenges to the EPA's Tailoring Rule have been filed.

Separately, on March 27, 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not impact any of Ameren's, Ameren Missouri's, or Genco's existing energy centers. Ameren anticipates this proposed rule could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2012. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants, particularly as it relates to power plant greenhouse gas emissions.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and 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 March 2012, the United States District Court for the Southern District of Mississippi dismissed a lawsuit called Comer v. Murphy Oil that alleged CO2 emissions from several industrial companies, including Ameren Missouri and Genco, created the atmospheric conditions that intensified Hurricane Katina, thereby causing property damage. The case has been appealed to the appellate court.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, 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. In late April 2012, the EPA issued another Section 114(a) request to Genco regarding projects at the Joppa energy center. EEI is in the process of responding to that data request.

Following the issuance of a Notice of Violation, in January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States District Court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for injunctive relief, including to require the installation of pollution control equipment, remain. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers, but the EPA has issued Notices of Violation under its NSR enforcement initiative against the company's Labadie, Meramec, and Sioux 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 Notices of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, 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 penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred. However, Ameren Missouri has concluded that, while a loss may be reasonably possible, the likelihood of loss is not probable. Therefore, no reserve has been established.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle 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 based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in November 2012 and to finalize the rule in April 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 rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of March 31, 2012, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. These 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 March 31, 2012, 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 March 31, 2012, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   102       $   174       $ 102   

Ameren Missouri

      3         4         3   

Ameren Illinois

      99         170         99   

 

(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 March 31, 2012, 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 March 31, 2012, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

Ameren Missouri has responsibility for the investigation and potential cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of March 31, 2012, 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 cleanup and therefore has no recorded liability at March 31, 2012, 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 2012. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2. As of March 31, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren Missouri has a liability of $0.3 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental 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 activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and 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.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri included certain capitalized costs associated with enhancements, or costs that would have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its 2010 electric rate case filing. However, in the July 2011 rate order, the MoPSC disallowed all of these capitalized costs associated with the rebuilding of the Taum Sauk energy center. See Note 2 - Rate and Regulatory Matters for additional information about the appeal of the MoPSC's July 2011 electric rate order.

Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of March 31, 2012, Ameren Missouri had an insurance receivable balance subject to liability coverage of $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. The United States Court of Appeals is expected to issue a decision during 2012. Separately, in April 2012, Ameren Missouri sued a different insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, filed in the Circuit Court for the City of St. Louis, State of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident.

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.

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 272 parties named in some pending cases and as few as two in others. In the cases pending as of March 31, 2012, the average number of parties was 82.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former electric generating plants. Certain former Ameren Illinois energy centers are now owned by either Genco or AERG. As a part of the transfer of energy center ownership in 2000 and 2003, Ameren Illinois contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to each 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 March 31, 2012:

 

Ameren    Ameren Missouri    Ameren Illinois    Genco   Total(a)
4    59    81    (b)   101

 

(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 March 31, 2012, six 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 March 31, 2012, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- million, respectively, recorded to represent their 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 to be recovered from a trust fund that was established when Ameren acquired IP. At March 31, 2012, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP's historical service territory. Similarly, the rider will permit 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 decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. On November 2, 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. Genco is challenging the State of Illinois' position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. Ameren and Genco do not believe that it is probable that the state of Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $27 million and $19 million, respectively.

Genco, excluding EEI, and AERG do not anticipate claiming any additional manufacturing exemptions or credits in 2012. EEI's request to renew its ability to claim new manufacturing exemptions or credits is currently being considered by the Illinois Department of Commerce and Economic Opportunity. Pending a response to its request, EEI's eligibility for continuing its use of the manufacturing exemption for 2012 is also pending. As a result, Genco, through EEI, recorded $1 million as of March 31, 2012, for its potential obligation to pay use tax on coal purchases that occurred during the first quarter of 2012.

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 Nuclear Plant in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at March 31, 2012. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages    

Maximum Assessments

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 industrywide 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 industrywide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We have also entered into various long-term commitments for purchased power and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Ameren Illinois contracted to purchase approximately 48,000 MWs of capacity for approximately $15 million during this period. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations, including the Illinois MPS that applies to our energy centers in Illinois, 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 proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for SO2 and NO2 emissions; the CSAPR, which requires further reductions of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; the MATS, which requires reduction of emissions of mercury, toxic 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. The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new regulations may be litigated, so the timing of their implementation is uncertain, as evidenced by the stay of the CSAPR by the United States Court of Appeals for the District of Columbia on December 30, 2011. 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. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our assessment of the potential impacts of the EPA's proposed regulation for CCR, the recently finalized MATS, the stayed CSAPR as currently designed, and the revised national ambient air quality standards for SO2 and NOx emissions as of March 31, 2012. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon a variety of factors including:

 

•  

additional federal or state requirements;

 

•  

regulation of greenhouse gas emissions;

 

•  

whether AER is granted a variance to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020;

 

•  

new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;

 

•  

additional rules governing air pollutant transport;

 

•  

finalized regulations under the Clean Water Act;

 

•  

CCR being classified as hazardous;

 

•  

whether the CSAPR is implemented and whether any modifications are made to its existing requirements;

 

•  

new technology;

 

•  

expected power prices;

 

•  

variations in costs of material or labor; and

 

•  

alternative compliance strategies or investment decisions.

 

      2012      2013 - 2016      2017 - 2021      Total  

AMO(a)

    $ 55       $ 325         -       $ 400       $ 845         -       $ 1,030       $ 1,225         -       $ 1,485   

Genco

      150         100         -         125         245         -         295         495         -         570   

AERG

      5         20         -         25         80         -         100         105         -         130   

Ameren

    $     210       $     445         -       $     550       $     1,170         -       $   1,425       $   1,825         -       $   2,185   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The decision to make pollution control equipment investments at our Merchant Generation business depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in the current year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. These scrubbers were originally expected to be installed in late 2013 and early 2014. The ultimate installation of these scrubbers, now estimated to occur between 2017 and 2021 in the table above, has been postponed until such time as the incremental investment necessary for completion is justified by visible market conditions. However, Genco will continue to incur capital costs related to the construction of these scrubbers. The table above includes Genco's estimated costs of approximately $150 million in 2012 and approximately $20 million annually, excluding capitalized interest, from 2013 through 2016 for the construction of the two scrubbers. In addition to Genco's reduction in estimated capital expenditures, AERG deferred precipitator upgrades at its E.D. Edwards energy center beyond 2016. Based on current environmental rules and regulations, if Merchant Generation and Genco do not complete these environmental upgrades by the beginning of 2015, Merchant Generation and Genco may need to reduce generation output at their energy centers to meet applicable emissions requirements. To achieve flexibility in its efforts to comply with the MPS by 2015, AER filed a request for a variance with the Illinois Pollution Control Board to extend certain compliance dates as discussed in more detail below.

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.

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 was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions. 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 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 were required in two phases beginning in 2012, with further reductions in 2014. 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, in the SO2 program, in the annual NOx, or in ozone season NOx program. Multiple legal challenges were filed requesting to have CSAPR partially or entirely vacated and to stay the implementation of the CSAPR while the court considers the challenges. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. The stay does not invalidate the rule, but only delays its implementation until a final court ruling is issued. The United States Court of Appeals for the District of Columbia has expedited its consideration of the regulation. The ultimate outcome of the challenges to the regulation is uncertain. The court could uphold CSAPR or remand it back to the EPA for partial or entire revision. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR.

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and they will require continuous monitoring systems that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be averaged for the entire power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2. It also announced plans for further reductions in the annual national ambient air quality standards for fine particulates. In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard again in 2013. The state of Illinois and the state of Missouri will be required to develop separate 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.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren Missouri's energy centers have historically burned, which will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next 10 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 additional emission reductions required by 2014 under the CSAPR, if ultimately enacted, the MATS, and other recently finalized or proposed EPA regulations.

Genco and AERG expect to install additional, or optimize existing, pollution control equipment, or modify or cease energy center operations to meet new and incremental emission reduction requirements under the MPS, the MATS, and the CSAPR as they become effective. Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. In May 2012, AER filed a request for a variance with the Illinois Pollution Control Board to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020. In exchange for delaying compliance with these emission levels through 2020, AER has proposed a plan that restricts its SO2 emissions through 2014 to levels lower than those required by the existing MPS, offsetting any environmental impact from the variance. AER has indicated to the Illinois Pollution Control Board that if a variance is not granted, or power prices do not materially increase, there is a significant risk that the Merchant Generation segment will have to mothball some of its unscrubbed coal-fired energy centers beginning in 2015. AER expects a decision from the Illinois Pollution Control Board by the end of 2012. To comply with the existing MPS and other air emissions laws and regulations, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NOx, and SO2. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco's Newton energy center. As discussed above, the timing of the installation of these scrubbers, as well as precipitator upgrades at AERG's E.D. Edwards energy center, have been delayed. Merchant Generation and Genco will continue to review and adjust their compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, environmental standards and compliance technologies, among other factors.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized 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, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, the CAIR, and 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. As noted above, on December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR including its allowance program.

Environmental regulations including the CAIR and the 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 uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. The CSAPR, however, did not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA issued a new type of emissions allowance for each program under the CSAPR. Any unused SO2 allowances, annual NOx allowances, and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco expect to have adequate CAIR allowances for 2012 to avoid needing to make external purchases.

Ameren, Ameren Missouri and Genco are studying their compliance options to identify additional opportunities that may exist for compliance in an economical fashion should the CSAPR become effective as issued. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, to install new or optimize existing pollution control equipment, to limit generation, or take other actions to achieve compliance with the CSAPR in future phase-in years.

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. The enactment of a climate change law could result in a significant rise in 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 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, economywide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.

In December 2009, the EPA issued its "endangerment finding" under the Clean Air Act which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized the "Tailoring Rule," that established new higher thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. Legal challenges to the EPA's Tailoring Rule have been filed.

Separately, on March 27, 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not impact any of Ameren's, Ameren Missouri's, or Genco's existing energy centers. Ameren anticipates this proposed rule could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2012. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants, particularly as it relates to power plant greenhouse gas emissions.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and 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 March 2012, the United States District Court for the Southern District of Mississippi dismissed a lawsuit called Comer v. Murphy Oil that alleged CO2 emissions from several industrial companies, including Ameren Missouri and Genco, created the atmospheric conditions that intensified Hurricane Katina, thereby causing property damage. The case has been appealed to the appellate court.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, 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. In late April 2012, the EPA issued another Section 114(a) request to Genco regarding projects at the Joppa energy center. EEI is in the process of responding to that data request.

Following the issuance of a Notice of Violation, in January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States District Court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for injunctive relief, including to require the installation of pollution control equipment, remain. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers, but the EPA has issued Notices of Violation under its NSR enforcement initiative against the company's Labadie, Meramec, and Sioux 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 Notices of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, 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 penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred. However, Ameren Missouri has concluded that, while a loss may be reasonably possible, the likelihood of loss is not probable. Therefore, no reserve has been established.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle 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 based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in November 2012 and to finalize the rule in April 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 rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of March 31, 2012, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. These 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 March 31, 2012, 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 March 31, 2012, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   102       $   174       $ 102   

Ameren Missouri

      3         4         3   

Ameren Illinois

      99         170         99   

 

(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 March 31, 2012, 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 March 31, 2012, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

Ameren Missouri has responsibility for the investigation and potential cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of March 31, 2012, 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 cleanup and therefore has no recorded liability at March 31, 2012, 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 2012. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2. As of March 31, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren Missouri has a liability of $0.3 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental 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 activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and 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.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri included certain capitalized costs associated with enhancements, or costs that would have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its 2010 electric rate case filing. However, in the July 2011 rate order, the MoPSC disallowed all of these capitalized costs associated with the rebuilding of the Taum Sauk energy center. See Note 2 - Rate and Regulatory Matters for additional information about the appeal of the MoPSC's July 2011 electric rate order.

Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of March 31, 2012, Ameren Missouri had an insurance receivable balance subject to liability coverage of $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. The United States Court of Appeals is expected to issue a decision during 2012. Separately, in April 2012, Ameren Missouri sued a different insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, filed in the Circuit Court for the City of St. Louis, State of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident.

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.

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 272 parties named in some pending cases and as few as two in others. In the cases pending as of March 31, 2012, the average number of parties was 82.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former electric generating plants. Certain former Ameren Illinois energy centers are now owned by either Genco or AERG. As a part of the transfer of energy center ownership in 2000 and 2003, Ameren Illinois contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to each 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 March 31, 2012:

 

Ameren    Ameren Missouri    Ameren Illinois    Genco   Total(a)
4    59    81    (b)   101

 

(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 March 31, 2012, six 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 March 31, 2012, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- million, respectively, recorded to represent their 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 to be recovered from a trust fund that was established when Ameren acquired IP. At March 31, 2012, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP's historical service territory. Similarly, the rider will permit 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 decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. On November 2, 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. Genco is challenging the State of Illinois' position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. Ameren and Genco do not believe that it is probable that the state of Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $27 million and $19 million, respectively.

Genco, excluding EEI, and AERG do not anticipate claiming any additional manufacturing exemptions or credits in 2012. EEI's request to renew its ability to claim new manufacturing exemptions or credits is currently being considered by the Illinois Department of Commerce and Economic Opportunity. Pending a response to its request, EEI's eligibility for continuing its use of the manufacturing exemption for 2012 is also pending. As a result, Genco, through EEI, recorded $1 million as of March 31, 2012, for its potential obligation to pay use tax on coal purchases that occurred during the first quarter of 2012.

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 Nuclear Plant in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at March 31, 2012. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages    

Maximum Assessments

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 industrywide 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 industrywide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We have also entered into various long-term commitments for purchased power and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Ameren Illinois contracted to purchase approximately 48,000 MWs of capacity for approximately $15 million during this period. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations, including the Illinois MPS that applies to our energy centers in Illinois, 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 proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for SO2 and NO2 emissions; the CSAPR, which requires further reductions of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; the MATS, which requires reduction of emissions of mercury, toxic 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. The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new regulations may be litigated, so the timing of their implementation is uncertain, as evidenced by the stay of the CSAPR by the United States Court of Appeals for the District of Columbia on December 30, 2011. 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. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our assessment of the potential impacts of the EPA's proposed regulation for CCR, the recently finalized MATS, the stayed CSAPR as currently designed, and the revised national ambient air quality standards for SO2 and NOx emissions as of March 31, 2012. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon a variety of factors including:

 

•  

additional federal or state requirements;

 

•  

regulation of greenhouse gas emissions;

 

•  

whether AER is granted a variance to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020;

 

•  

new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;

 

•  

additional rules governing air pollutant transport;

 

•  

finalized regulations under the Clean Water Act;

 

•  

CCR being classified as hazardous;

 

•  

whether the CSAPR is implemented and whether any modifications are made to its existing requirements;

 

•  

new technology;

 

•  

expected power prices;

 

•  

variations in costs of material or labor; and

 

•  

alternative compliance strategies or investment decisions.

 

      2012      2013 - 2016      2017 - 2021      Total  

AMO(a)

    $ 55       $ 325         -       $ 400       $ 845         -       $ 1,030       $ 1,225         -       $ 1,485   

Genco

      150         100         -         125         245         -         295         495         -         570   

AERG

      5         20         -         25         80         -         100         105         -         130   

Ameren

    $     210       $     445         -       $     550       $     1,170         -       $   1,425       $   1,825         -       $   2,185   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The decision to make pollution control equipment investments at our Merchant Generation business depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in the current year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. These scrubbers were originally expected to be installed in late 2013 and early 2014. The ultimate installation of these scrubbers, now estimated to occur between 2017 and 2021 in the table above, has been postponed until such time as the incremental investment necessary for completion is justified by visible market conditions. However, Genco will continue to incur capital costs related to the construction of these scrubbers. The table above includes Genco's estimated costs of approximately $150 million in 2012 and approximately $20 million annually, excluding capitalized interest, from 2013 through 2016 for the construction of the two scrubbers. In addition to Genco's reduction in estimated capital expenditures, AERG deferred precipitator upgrades at its E.D. Edwards energy center beyond 2016. Based on current environmental rules and regulations, if Merchant Generation and Genco do not complete these environmental upgrades by the beginning of 2015, Merchant Generation and Genco may need to reduce generation output at their energy centers to meet applicable emissions requirements. To achieve flexibility in its efforts to comply with the MPS by 2015, AER filed a request for a variance with the Illinois Pollution Control Board to extend certain compliance dates as discussed in more detail below.

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.

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 was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions. 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 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 were required in two phases beginning in 2012, with further reductions in 2014. 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, in the SO2 program, in the annual NOx, or in ozone season NOx program. Multiple legal challenges were filed requesting to have CSAPR partially or entirely vacated and to stay the implementation of the CSAPR while the court considers the challenges. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. The stay does not invalidate the rule, but only delays its implementation until a final court ruling is issued. The United States Court of Appeals for the District of Columbia has expedited its consideration of the regulation. The ultimate outcome of the challenges to the regulation is uncertain. The court could uphold CSAPR or remand it back to the EPA for partial or entire revision. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR.

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and they will require continuous monitoring systems that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be averaged for the entire power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2. It also announced plans for further reductions in the annual national ambient air quality standards for fine particulates. In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard again in 2013. The state of Illinois and the state of Missouri will be required to develop separate 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.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren Missouri's energy centers have historically burned, which will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next 10 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 additional emission reductions required by 2014 under the CSAPR, if ultimately enacted, the MATS, and other recently finalized or proposed EPA regulations.

Genco and AERG expect to install additional, or optimize existing, pollution control equipment, or modify or cease energy center operations to meet new and incremental emission reduction requirements under the MPS, the MATS, and the CSAPR as they become effective. Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. In May 2012, AER filed a request for a variance with the Illinois Pollution Control Board to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020. In exchange for delaying compliance with these emission levels through 2020, AER has proposed a plan that restricts its SO2 emissions through 2014 to levels lower than those required by the existing MPS, offsetting any environmental impact from the variance. AER has indicated to the Illinois Pollution Control Board that if a variance is not granted, or power prices do not materially increase, there is a significant risk that the Merchant Generation segment will have to mothball some of its unscrubbed coal-fired energy centers beginning in 2015. AER expects a decision from the Illinois Pollution Control Board by the end of 2012. To comply with the existing MPS and other air emissions laws and regulations, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NOx, and SO2. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco's Newton energy center. As discussed above, the timing of the installation of these scrubbers, as well as precipitator upgrades at AERG's E.D. Edwards energy center, have been delayed. Merchant Generation and Genco will continue to review and adjust their compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, environmental standards and compliance technologies, among other factors.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized 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, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, the CAIR, and 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. As noted above, on December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR including its allowance program.

Environmental regulations including the CAIR and the 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 uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. The CSAPR, however, did not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA issued a new type of emissions allowance for each program under the CSAPR. Any unused SO2 allowances, annual NOx allowances, and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco expect to have adequate CAIR allowances for 2012 to avoid needing to make external purchases.

Ameren, Ameren Missouri and Genco are studying their compliance options to identify additional opportunities that may exist for compliance in an economical fashion should the CSAPR become effective as issued. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, to install new or optimize existing pollution control equipment, to limit generation, or take other actions to achieve compliance with the CSAPR in future phase-in years.

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. The enactment of a climate change law could result in a significant rise in 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 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, economywide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.

In December 2009, the EPA issued its "endangerment finding" under the Clean Air Act which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized the "Tailoring Rule," that established new higher thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. Legal challenges to the EPA's Tailoring Rule have been filed.

Separately, on March 27, 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not impact any of Ameren's, Ameren Missouri's, or Genco's existing energy centers. Ameren anticipates this proposed rule could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2012. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants, particularly as it relates to power plant greenhouse gas emissions.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and 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 March 2012, the United States District Court for the Southern District of Mississippi dismissed a lawsuit called Comer v. Murphy Oil that alleged CO2 emissions from several industrial companies, including Ameren Missouri and Genco, created the atmospheric conditions that intensified Hurricane Katina, thereby causing property damage. The case has been appealed to the appellate court.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, 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. In late April 2012, the EPA issued another Section 114(a) request to Genco regarding projects at the Joppa energy center. EEI is in the process of responding to that data request.

Following the issuance of a Notice of Violation, in January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States District Court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for injunctive relief, including to require the installation of pollution control equipment, remain. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers, but the EPA has issued Notices of Violation under its NSR enforcement initiative against the company's Labadie, Meramec, and Sioux 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 Notices of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, 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 penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred. However, Ameren Missouri has concluded that, while a loss may be reasonably possible, the likelihood of loss is not probable. Therefore, no reserve has been established.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle 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 based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in November 2012 and to finalize the rule in April 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 rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of March 31, 2012, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. These 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 March 31, 2012, 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 March 31, 2012, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   102       $   174       $ 102   

Ameren Missouri

      3         4         3   

Ameren Illinois

      99         170         99   

 

(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 March 31, 2012, 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 March 31, 2012, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

Ameren Missouri has responsibility for the investigation and potential cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of March 31, 2012, 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 cleanup and therefore has no recorded liability at March 31, 2012, 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 2012. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2. As of March 31, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren Missouri has a liability of $0.3 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental 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 activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and 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.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri included certain capitalized costs associated with enhancements, or costs that would have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its 2010 electric rate case filing. However, in the July 2011 rate order, the MoPSC disallowed all of these capitalized costs associated with the rebuilding of the Taum Sauk energy center. See Note 2 - Rate and Regulatory Matters for additional information about the appeal of the MoPSC's July 2011 electric rate order.

Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of March 31, 2012, Ameren Missouri had an insurance receivable balance subject to liability coverage of $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. The United States Court of Appeals is expected to issue a decision during 2012. Separately, in April 2012, Ameren Missouri sued a different insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, filed in the Circuit Court for the City of St. Louis, State of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident.

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.

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 272 parties named in some pending cases and as few as two in others. In the cases pending as of March 31, 2012, the average number of parties was 82.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former electric generating plants. Certain former Ameren Illinois energy centers are now owned by either Genco or AERG. As a part of the transfer of energy center ownership in 2000 and 2003, Ameren Illinois contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to each 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 March 31, 2012:

 

Ameren    Ameren Missouri    Ameren Illinois    Genco   Total(a)
4    59    81    (b)   101

 

(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 March 31, 2012, six 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 March 31, 2012, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- million, respectively, recorded to represent their 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 to be recovered from a trust fund that was established when Ameren acquired IP. At March 31, 2012, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP's historical service territory. Similarly, the rider will permit 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 decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. On November 2, 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. Genco is challenging the State of Illinois' position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. Ameren and Genco do not believe that it is probable that the state of Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $27 million and $19 million, respectively.

Genco, excluding EEI, and AERG do not anticipate claiming any additional manufacturing exemptions or credits in 2012. EEI's request to renew its ability to claim new manufacturing exemptions or credits is currently being considered by the Illinois Department of Commerce and Economic Opportunity. Pending a response to its request, EEI's eligibility for continuing its use of the manufacturing exemption for 2012 is also pending. As a result, Genco, through EEI, recorded $1 million as of March 31, 2012, for its potential obligation to pay use tax on coal purchases that occurred during the first quarter of 2012.

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 Nuclear Plant in this report.

Callaway Energy Center

The following table presents insurance coverage at Ameren Missouri's Callaway energy center at March 31, 2012. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.

 

Type and Source of Coverage    Maximum Coverages    

Maximum Assessments

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 industrywide 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 industrywide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by, insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren's and Ameren Missouri's results of operations, financial position, or liquidity.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We have also entered into various long-term commitments for purchased power and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

In the second quarter of 2012, Ameren Illinois used a RFP process, administered by the IPA, to contract capacity and energy products for the period from June 1, 2012, through May 31, 2015. Ameren Illinois contracted to purchase approximately 48,000 MWs of capacity for approximately $15 million during this period. Ameren Illinois is currently reviewing the results of the energy products procurement proceeding.

Environmental Matters

We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures.

In addition to existing laws and regulations, including the Illinois MPS that applies to our energy centers in Illinois, 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 proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions; revised national ambient air quality standards for SO2 and NO2 emissions; the CSAPR, which requires further reductions of SO2 and NOx emissions from power plants; a regulation governing management of CCR and coal ash impoundments; the MATS, which requires reduction of emissions of mercury, toxic 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. The EPA has proposed CO2 limits for new coal-fired and natural gas-fired combined cycle units and is expected to propose limits for existing units in the future. These new regulations may be litigated, so the timing of their implementation is uncertain, as evidenced by the stay of the CSAPR by the United States Court of Appeals for the District of Columbia on December 30, 2011. 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. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures.

The estimates in the table below contain all of the known capital costs to comply with existing environmental regulations and our assessment of the potential impacts of the EPA's proposed regulation for CCR, the recently finalized MATS, the stayed CSAPR as currently designed, and the revised national ambient air quality standards for SO2 and NOx emissions as of March 31, 2012. The estimates in the table below assume that CCR will continue to be regarded as nonhazardous. The estimates in the table below do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures as our evaluation of those impacts is ongoing. The estimates shown in the table below could change significantly depending upon a variety of factors including:

 

•  

additional federal or state requirements;

 

•  

regulation of greenhouse gas emissions;

 

•  

whether AER is granted a variance to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020;

 

•  

new national ambient air quality standards or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions;

 

•  

additional rules governing air pollutant transport;

 

•  

finalized regulations under the Clean Water Act;

 

•  

CCR being classified as hazardous;

 

•  

whether the CSAPR is implemented and whether any modifications are made to its existing requirements;

 

•  

new technology;

 

•  

expected power prices;

 

•  

variations in costs of material or labor; and

 

•  

alternative compliance strategies or investment decisions.

 

      2012      2013 - 2016      2017 - 2021      Total  

AMO(a)

    $ 55       $ 325         -       $ 400       $ 845         -       $ 1,030       $ 1,225         -       $ 1,485   

Genco

      150         100         -         125         245         -         295         495         -         570   

AERG

      5         20         -         25         80         -         100         105         -         130   

Ameren

    $     210       $     445         -       $     550       $     1,170         -       $   1,425       $   1,825         -       $   2,185   

 

(a) Ameren Missouri's expenditures are expected to be recoverable from ratepayers.

The decision to make pollution control equipment investments at our Merchant Generation business depends on whether the expected future market price for power reflects the increased cost for environmental compliance. During early 2012, the observable market price for power for delivery in the current year and in future years sharply declined below 2011 levels primarily because of declining natural gas prices, as well as the impact from the stay of the CSAPR. As a result of this sharp decline in the market price for power, as well as uncertain environmental regulations, Genco decelerated the construction of two scrubbers at its Newton energy center. These scrubbers were originally expected to be installed in late 2013 and early 2014. The ultimate installation of these scrubbers, now estimated to occur between 2017 and 2021 in the table above, has been postponed until such time as the incremental investment necessary for completion is justified by visible market conditions. However, Genco will continue to incur capital costs related to the construction of these scrubbers. The table above includes Genco's estimated costs of approximately $150 million in 2012 and approximately $20 million annually, excluding capitalized interest, from 2013 through 2016 for the construction of the two scrubbers. In addition to Genco's reduction in estimated capital expenditures, AERG deferred precipitator upgrades at its E.D. Edwards energy center beyond 2016. Based on current environmental rules and regulations, if Merchant Generation and Genco do not complete these environmental upgrades by the beginning of 2015, Merchant Generation and Genco may need to reduce generation output at their energy centers to meet applicable emissions requirements. To achieve flexibility in its efforts to comply with the MPS by 2015, AER filed a request for a variance with the Illinois Pollution Control Board to extend certain compliance dates as discussed in more detail below.

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.

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 was to become effective on January 1, 2012, for SO2 and annual NOx reductions and on May 1, 2012, for ozone season NOx reductions. 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 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 were required in two phases beginning in 2012, with further reductions in 2014. 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, in the SO2 program, in the annual NOx, or in ozone season NOx program. Multiple legal challenges were filed requesting to have CSAPR partially or entirely vacated and to stay the implementation of the CSAPR while the court considers the challenges. On December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. The stay does not invalidate the rule, but only delays its implementation until a final court ruling is issued. The United States Court of Appeals for the District of Columbia has expedited its consideration of the regulation. The ultimate outcome of the challenges to the regulation is uncertain. The court could uphold CSAPR or remand it back to the EPA for partial or entire revision. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR.

In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and they will require continuous monitoring systems that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however, emission compliance can be averaged for the entire power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016.

Separately, in January and June 2010, the EPA finalized new ambient air quality standards for SO2 and NO2. It also announced plans for further reductions in the annual national ambient air quality standards for fine particulates. In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standard for ozone. The EPA is required to revisit this standard again in 2013. The state of Illinois and the state of Missouri will be required to develop separate 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.

Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly higher volumes of lower-sulfur-content coal than Ameren Missouri's energy centers have historically burned, which will allow Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers within its coal-fired fleet during the next 10 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 additional emission reductions required by 2014 under the CSAPR, if ultimately enacted, the MATS, and other recently finalized or proposed EPA regulations.

Genco and AERG expect to install additional, or optimize existing, pollution control equipment, or modify or cease energy center operations to meet new and incremental emission reduction requirements under the MPS, the MATS, and the CSAPR as they become effective. Under the MPS, as amended, Illinois generators are required to reduce mercury, SO2, and NOx emissions by 2015. In May 2012, AER filed a request for a variance with the Illinois Pollution Control Board to extend compliance dates for SO2 emission levels contained within the MPS for five years until December 31, 2020. In exchange for delaying compliance with these emission levels through 2020, AER has proposed a plan that restricts its SO2 emissions through 2014 to levels lower than those required by the existing MPS, offsetting any environmental impact from the variance. AER has indicated to the Illinois Pollution Control Board that if a variance is not granted, or power prices do not materially increase, there is a significant risk that the Merchant Generation segment will have to mothball some of its unscrubbed coal-fired energy centers beginning in 2015. AER expects a decision from the Illinois Pollution Control Board by the end of 2012. To comply with the existing MPS and other air emissions laws and regulations, Genco and AERG are installing equipment designed to reduce their emissions of mercury, NOx, and SO2. Genco and AERG have installed a total of three scrubbers at two energy centers. Two additional scrubbers are being constructed at Genco's Newton energy center. As discussed above, the timing of the installation of these scrubbers, as well as precipitator upgrades at AERG's E.D. Edwards energy center, have been delayed. Merchant Generation and Genco will continue to review and adjust their compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, environmental standards and compliance technologies, among other factors.

The completion of Ameren's, Ameren Missouri's and Genco's review of recently finalized 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, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets.

Emission Allowances

The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, the CAIR, and 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. As noted above, on December 30, 2011, the United States Court of Appeals for the District of Columbia issued a stay of the CSAPR. Until the CSAPR appeal process is concluded, the EPA will continue to administer the CAIR including its allowance program.

Environmental regulations including the CAIR and the 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 uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. The CSAPR, however, did not rely upon the acid rain program, the NOx budget trading program, or CAIR allowances for its allowance allocation program. Instead, the EPA issued a new type of emissions allowance for each program under the CSAPR. Any unused SO2 allowances, annual NOx allowances, and ozone season NOx allowances issued under CAIR cannot be used for compliance with CSAPR. Ameren, Ameren Missouri and Genco expect to have adequate CAIR allowances for 2012 to avoid needing to make external purchases.

Ameren, Ameren Missouri and Genco are studying their compliance options to identify additional opportunities that may exist for compliance in an economical fashion should the CSAPR become effective as issued. Ameren, Ameren Missouri and Genco may be required to purchase emission allowances, if available, to install new or optimize existing pollution control equipment, to limit generation, or take other actions to achieve compliance with the CSAPR in future phase-in years.

Global Climate Change

State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions and to address global climate change. Potential impacts from any climate change legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a "safety valve" provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. The enactment of a climate change law could result in a significant rise in 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 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, economywide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas.

In December 2009, the EPA issued its "endangerment finding" under the Clean Air Act which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application.

Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA finalized the "Tailoring Rule," that established new higher thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology, if any, to control greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. Legal challenges to the EPA's Tailoring Rule have been filed.

Separately, on March 27, 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired electric energy centers and therefore does not impact any of Ameren's, Ameren Missouri's, or Genco's existing energy centers. Ameren anticipates this proposed rule could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected in 2012. Any federal climate change legislation that is enacted may preempt the EPA's regulation of greenhouse gas emissions, including the Tailoring Rule and the Carbon Pollution Standard for New Power Plants, particularly as it relates to power plant greenhouse gas emissions.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Moreover, to the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. Excessive costs to comply with future legislation or regulations might force Ameren, Ameren Missouri and 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 March 2012, the United States District Court for the Southern District of Mississippi dismissed a lawsuit called Comer v. Murphy Oil that alleged CO2 emissions from several industrial companies, including Ameren Missouri and Genco, created the atmospheric conditions that intensified Hurricane Katina, thereby causing property damage. The case has been appealed to the appellate court.

The impact on us of future initiatives related to greenhouse gas emissions and global climate change is unknown. Compliance costs could increase as future federal legislative, federal regulatory, and state-sponsored initiatives to control greenhouse gases continue to progress, making it more likely that some form of greenhouse gas emissions control will eventually be required. Since these initiatives continue to evolve, 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. In late April 2012, the EPA issued another Section 114(a) request to Genco regarding projects at the Joppa energy center. EEI is in the process of responding to that data request.

Following the issuance of a Notice of Violation, in January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the United States District Court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for injunctive relief, including to require the installation of pollution control equipment, remain. At present, the complaint does not include Ameren Missouri's other coal-fired energy centers, but the EPA has issued Notices of Violation under its NSR enforcement initiative against the company's Labadie, Meramec, and Sioux 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 Notices of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts.

Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren, 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 penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred. However, Ameren Missouri has concluded that, while a loss may be reasonably possible, the likelihood of loss is not probable. Therefore, no reserve has been established.

Clean Water Act

In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25 percent of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to 0.5 feet per second. The proposed rule also requires plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in July 2012, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle 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 based on the effectiveness of available control technology. The EPA is engaged in information collection and analysis activities in support of this rulemaking. It has indicated that it expects to issue a proposed rule in November 2012 and to finalize the rule in April 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 rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003. As part of each transfer, Ameren Illinois contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of March 31, 2012, Ameren and Ameren Illinois owned or were otherwise responsible for 44 former MGP sites in Illinois. These 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 March 31, 2012, 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 March 31, 2012, the estimated probable obligation to remediate these MGP sites.

 

      Estimate          
      Low      High      Recorded
   Liability(a)		  

Ameren

    $   102       $   174       $ 102   

Ameren Missouri

      3         4         3   

Ameren Illinois

      99         170         99   

 

(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 March 31, 2012, 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 March 31, 2012, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites.

Ameren Missouri has responsibility for the investigation and potential cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of March 31, 2012, 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 cleanup and therefore has no recorded liability at March 31, 2012, 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 2012. Once the EPA has selected a remedy, if any, it would begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in the Sauget Area 2. As of March 31, 2012, Ameren Missouri estimated its obligation at $0.3 million to $10 million. Ameren Missouri has a liability of $0.3 million recorded to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental 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 activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. Additionally, in January 2010, EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and 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.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010.

Ameren Missouri included certain capitalized costs associated with enhancements, or costs that would have been incurred absent the breach, at the rebuilt Taum Sauk energy center not recovered from property insurers in its 2010 electric rate case filing. However, in the July 2011 rate order, the MoPSC disallowed all of these capitalized costs associated with the rebuilding of the Taum Sauk energy center. See Note 2 - Rate and Regulatory Matters for additional information about the appeal of the MoPSC's July 2011 electric rate order.

Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of March 31, 2012, Ameren Missouri had an insurance receivable balance subject to liability coverage of $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. The United States Court of Appeals is expected to issue a decision during 2012. Separately, in April 2012, Ameren Missouri sued a different insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, filed in the Circuit Court for the City of St. Louis, State of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses experienced from the incident.

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.

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 272 parties named in some pending cases and as few as two in others. In the cases pending as of March 31, 2012, the average number of parties was 82.

The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former electric generating plants. Certain former Ameren Illinois energy centers are now owned by either Genco or AERG. As a part of the transfer of energy center ownership in 2000 and 2003, Ameren Illinois contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to each 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 March 31, 2012:

 

Ameren    Ameren Missouri    Ameren Illinois    Genco   Total(a)
4    59    81    (b)   101

 

(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 March 31, 2012, six 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 March 31, 2012, Ameren, Ameren Missouri, Ameren Illinois and Genco had liabilities of $19 million, $7 million, $12 million, and $- million, respectively, recorded to represent their 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 to be recovered from a trust fund that was established when Ameren acquired IP. At March 31, 2012, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. Following the Ameren Illinois Merger, this rider is applicable only for claims that occurred within IP's historical service territory. Similarly, the rider will permit 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 decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. On November 2, 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. Genco is challenging the State of Illinois' position. In December 2011, EEI filed a request for review by the Informal Conference Board of the Illinois Department of Revenue. Ameren and Genco do not believe that it is probable that the state of Illinois will prevail and therefore have not recorded a charge to earnings for the loss contingency. From the second quarter of 2010 through December 31, 2011, Ameren and Genco claimed manufacturing exemptions and credits of $27 million and $19 million, respectively.

Genco, excluding EEI, and AERG do not anticipate claiming any additional manufacturing exemptions or credits in 2012. EEI's request to renew its ability to claim new manufacturing exemptions or credits is currently being considered by the Illinois Department of Commerce and Economic Opportunity. Pending a response to its request, EEI's eligibility for continuing its use of the manufacturing exemption for 2012 is also pending. As a result, Genco, through EEI, recorded $1 million as of March 31, 2012, for its potential obligation to pay use tax on coal purchases that occurred during the first quarter of 2012.

Callaway Nuclear Plant
Callaway Nuclear Plant 

NOTE 10 - CALLAWAY ENERGY CENTER

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear power plants. Under the NWPA, Ameren and other utilities who own and operate those plants are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatt hour generated by those plants and sold. The NWPA also requires the DOE to review the nuclear waste fee against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren and other utilities have entered into standard contracts with the federal government. The government, represented by the DOE, implements these provisions of the NWPA. Consistent with the NWPA and its contract, Ameren Missouri collects one mill from its electric customers for each kilowatt hour of electricity that it generates and sells from its Callaway energy center.

Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government has acknowledged since at least 1994 that it would not meet that deadline. The federal government is not currently predicting when it will begin to meet its disposal obligation. Ameren Missouri has sufficient installed capacity at its Callaway energy center to store the spent nuclear fuel generated at Callaway through 2020 and has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center's current licensed life.

Until January 2009, the DOE program provided for spent nuclear fuel disposal to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. In January 2009, the Obama administration announced that a repository at Yucca Mountain was unworkable and took steps to terminate the Yucca Mountain program, while acknowledging the federal government's continuing obligation to dispose of utilities' spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund. Most of these recommendations require action by the DOE and the United States Congress.

In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit seeking the suspension of the one mill nuclear waste fee. They allege that the DOE's failure to undertake an appropriate fee adequacy review reflects the current unsettled state of the nuclear waste program. That case is pending. The DOE delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operation of the energy center.

As a result of DOE's failure to build a repository for nuclear waste or otherwise fulfill its contractual obligations, Ameren Missouri and other nuclear power plant owners have also sued DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover its costs, which would not have been incurred had DOE performed its contractual obligations. These costs included the reracking of the Callaway energy center's spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes. In June 2011, the parties reached a settlement that included a payment to Ameren Missouri 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. In March 2012, Ameren Missouri submitted its 2011 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2011 cost reimbursement of $1 million during the third quarter of 2012.

In December 2011, Ameren Missouri submitted a license extension application with the NRC to extend its Callaway energy center's operating license from 2024 to 2044. There is no date by which the NRC must act in this relicensing request. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility by 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 current operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 2011, 2010, and 2009. 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. This cost study was filed with the MoPSC in September 2011. After considering the results of this updated cost study and associated financial analysis, Ameren Missouri recommended to the MoPSC that the current rate of deposits to the trust fund continues to be appropriate and does not need to be changed. A decision from the MoPSC is still pending. If Ameren Missouri's operating license extension application is approved by the NRC, a revised financial analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension. 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 liability.

See Note 2 - Rate and Regulatory Matters for additional information related to the Callaway energy center.

Callaway Nuclear Plant 

NOTE 10 - CALLAWAY ENERGY CENTER

Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear power plants. Under the NWPA, Ameren and other utilities who own and operate those plants are responsible for paying the disposal costs. The NWPA established the fee that these utilities pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatt hour generated by those plants and sold. The NWPA also requires the DOE to review the nuclear waste fee against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren and other utilities have entered into standard contracts with the federal government. The government, represented by the DOE, implements these provisions of the NWPA. Consistent with the NWPA and its contract, Ameren Missouri collects one mill from its electric customers for each kilowatt hour of electricity that it generates and sells from its Callaway energy center.

Although both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, the federal government has acknowledged since at least 1994 that it would not meet that deadline. The federal government is not currently predicting when it will begin to meet its disposal obligation. Ameren Missouri has sufficient installed capacity at its Callaway energy center to store the spent nuclear fuel generated at Callaway through 2020 and has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center's current licensed life.

Until January 2009, the DOE program provided for spent nuclear fuel disposal to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. In January 2009, the Obama administration announced that a repository at Yucca Mountain was unworkable and took steps to terminate the Yucca Mountain program, while acknowledging the federal government's continuing obligation to dispose of utilities' spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund. Most of these recommendations require action by the DOE and the United States Congress.

In view of the federal government's efforts to terminate the Yucca Mountain program, the Nuclear Energy Institute, a number of individual utilities, and the National Association of Regulatory Utility Commissioners sued the DOE in the United States Court of Appeals for the District of Columbia Circuit seeking the suspension of the one mill nuclear waste fee. They allege that the DOE's failure to undertake an appropriate fee adequacy review reflects the current unsettled state of the nuclear waste program. That case is pending. The DOE delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operation of the energy center.

As a result of DOE's failure to build a repository for nuclear waste or otherwise fulfill its contractual obligations, Ameren Missouri and other nuclear power plant owners have also sued DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover its costs, which would not have been incurred had DOE performed its contractual obligations. These costs included the reracking of the Callaway energy center's spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes. In June 2011, the parties reached a settlement that included a payment to Ameren Missouri 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. In March 2012, Ameren Missouri submitted its 2011 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2011 cost reimbursement of $1 million during the third quarter of 2012.

In December 2011, Ameren Missouri submitted a license extension application with the NRC to extend its Callaway energy center's operating license from 2024 to 2044. There is no date by which the NRC must act in this relicensing request. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility by 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 current operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 2011, 2010, and 2009. 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. This cost study was filed with the MoPSC in September 2011. After considering the results of this updated cost study and associated financial analysis, Ameren Missouri recommended to the MoPSC that the current rate of deposits to the trust fund continues to be appropriate and does not need to be changed. A decision from the MoPSC is still pending. If Ameren Missouri's operating license extension application is approved by the NRC, a revised financial analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension. 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 liability.

See Note 2 - Rate and Regulatory Matters for additional information related to the Callaway energy center.

Asset Impairment
Asset Impairment 

NOTE 11 - ASSET IMPAIRMENT

We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value, or book value, of such assets may not be recoverable. Under applicable accounting guidance, whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the estimated undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value.

Power prices in the Midwest affect the amount of revenues and cash flows Merchant Generation and Genco can realize by marketing power into the wholesale and retail markets. During the first quarter of 2012, the observable market price for power for delivery in the current year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. For example, from December 31, 2011, through February 29, 2012, the market price for power at the Indiana Hub for delivery in the current year decreased by 14%. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012. The sharp decline in the market price of power in 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco's Newton energy center scrubber project, caused Merchant Generation and Genco to evaluate, during the first quarter of 2012, whether the carrying value of their energy centers were recoverable. The carrying values of Merchant Generation's and Genco's energy centers exceeded their estimated fair values. However, under the applicable accounting guidance, if undiscounted future cash flows from these long-lived assets exceed their carrying values, the assets are deemed unimpaired, and no impairment loss is recognized, even if the carrying values of the assets exceed estimated fair values. Only AERG's Duck Creek energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG's Duck Creek energy center to its estimated fair value during the first quarter of 2012. This impairment charge was included in Ameren's results and in the Merchant Generation's segment results for the first quarter of 2012.

Key assumptions used in the determination of estimated undiscounted cash flows of the Merchant Generation and Genco long-lived assets tested for impairment included the forward price projections for energy and fuel costs, the expected life of the energy center, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate, were used to estimate the fair value of the long-lived assets of the Duck Creek energy center. The fair value estimate of the long-lived assets of the Duck Creek energy center was based on the income approach, which considers discounted future cash flows. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.

Long-lived assets are measured at fair value on a nonrecurring basis if triggering events require us to perform impairment tests. The carrying value of Merchant Generation's and Genco's net plant assets at March 31, 2012, was $2.6 billion and $2.2 billion, respectively. As of March 31, 2012, after the impairment of the Duck Creek energy center, Merchant Generation and Genco believed the carrying value of their energy centers exceeded their estimated fair values by an amount significantly in excess of $1 billion. Merchant Generation and Genco will continue to monitor the market price for power and the related impact on electric margin and other events or changes in circumstances that indicate that the carrying value of their energy centers may not be recoverable. Merchant Generation and Genco could recognize additional, material long-lived asset impairment charges in the future as a result of factors outside their control, such as changes in power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of Merchant Generation's and Genco's energy centers, and also as a result of factors that may be within their control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell their energy centers.

This asset impairment charge did not result in a violation of any Ameren debt covenants or counterparty agreements.

Asset Impairment 

NOTE 11 - ASSET IMPAIRMENT

We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value, or book value, of such assets may not be recoverable. Under applicable accounting guidance, whether an impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the estimated undiscounted cash flows, we recognize an impairment charge equal to the carrying value of the assets in excess of estimated fair value.

Power prices in the Midwest affect the amount of revenues and cash flows Merchant Generation and Genco can realize by marketing power into the wholesale and retail markets. During the first quarter of 2012, the observable market price for power for delivery in the current year and in future years in the Midwest sharply declined below 2011 levels primarily because of declining natural gas prices and the impact of the stay of the CSAPR. For example, from December 31, 2011, through February 29, 2012, the market price for power at the Indiana Hub for delivery in the current year decreased by 14%. As a result of this sharp decline in the market price of power and the related impact on electric margins, Genco decelerated the construction of two scrubbers at its Newton energy center in February 2012. The sharp decline in the market price of power in 2012 and the related impact on electric margins, as well as the deceleration of construction of Genco's Newton energy center scrubber project, caused Merchant Generation and Genco to evaluate, during the first quarter of 2012, whether the carrying value of their energy centers were recoverable. The carrying values of Merchant Generation's and Genco's energy centers exceeded their estimated fair values. However, under the applicable accounting guidance, if undiscounted future cash flows from these long-lived assets exceed their carrying values, the assets are deemed unimpaired, and no impairment loss is recognized, even if the carrying values of the assets exceed estimated fair values. Only AERG's Duck Creek energy center's carrying value exceeded its estimated undiscounted future cash flows. As a result, Ameren recorded a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG's Duck Creek energy center to its estimated fair value during the first quarter of 2012. This impairment charge was included in Ameren's results and in the Merchant Generation's segment results for the first quarter of 2012.

Key assumptions used in the determination of estimated undiscounted cash flows of the Merchant Generation and Genco long-lived assets tested for impairment included the forward price projections for energy and fuel costs, the expected life of the energy center, environmental compliance costs and strategies, and operating costs. Those same cash flow assumptions, along with a discount rate, were used to estimate the fair value of the long-lived assets of the Duck Creek energy center. The fair value estimate of the long-lived assets of the Duck Creek energy center was based on the income approach, which considers discounted future cash flows. The fair value estimate was determined using observable inputs and significant unobservable inputs, which are Level 3 inputs as defined by accounting guidance for fair value measurements.

Long-lived assets are measured at fair value on a nonrecurring basis if triggering events require us to perform impairment tests. The carrying value of Merchant Generation's and Genco's net plant assets at March 31, 2012, was $2.6 billion and $2.2 billion, respectively. As of March 31, 2012, after the impairment of the Duck Creek energy center, Merchant Generation and Genco believed the carrying value of their energy centers exceeded their estimated fair values by an amount significantly in excess of $1 billion. Merchant Generation and Genco will continue to monitor the market price for power and the related impact on electric margin and other events or changes in circumstances that indicate that the carrying value of their energy centers may not be recoverable. Merchant Generation and Genco could recognize additional, material long-lived asset impairment charges in the future as a result of factors outside their control, such as changes in power or fuel costs, administrative action or inaction by regulatory agencies and new environmental laws and regulations that could reduce the expected useful lives of Merchant Generation's and Genco's energy centers, and also as a result of factors that may be within their control, such as a failure to achieve forecasted operating results and cash flows, unfavorable changes in forecasted operating results and cash flows, or decisions to shut down, mothball or sell their energy centers.

This asset impairment charge did not result in a violation of any Ameren debt covenants or counterparty agreements.

Retirement Benefits
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 expense or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2011, its estimated investment performance through March 31, 2012, and its pension funding policy, Ameren expects to make annual contributions of $90 million to $150 million in each of the next five years, with aggregate estimated contributions of $580 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 expense.

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three months ended March 31, 2012, and 2011:

 

     Pension  Benefits(a)     Postretirement  Benefits(a)  
     Three Months     Three Months  
     2012     2011     2012     2011  

Service cost

    $ 21      $ 20      $ 6      $ 6   

Interest cost

      43        45        14        15   

Expected return on plan assets

      (54 )      (54 )      (14 )      (14 ) 

Amortization of:

         

Prior service cost (benefit)

     —          —          (1 )      (2 ) 

Actuarial loss

     20        11        4        1   
  

 

 

    

 

 

    

 

 

    

 

 

  

Net periodic benefit cost

    $ 30      $ 22      $ 9      $ 6   
  

 

 

    

 

 

    

 

 

    

 

 

  

 

(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 months ended March 31, 2012, and 2011:

 

     Pension Costs      Postretirement Costs  
     Three Months      Three Months  
     2012      2011      2012      2011  

Ameren Missouri

    $ 16       $ 14       $ 5       $ 3   

Ameren Illinois

      10         5         2         2   

Genco

      3         2         2         1   

Other

      1         1         —           —     
  

 

 

     

 

 

     

 

 

     

 

 

  

Ameren(a)

   $ 30       $ 22       $ 9       $ 6   
  

 

 

     

 

 

     

 

 

     

 

 

  

 

(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 expense or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2011, its estimated investment performance through March 31, 2012, and its pension funding policy, Ameren expects to make annual contributions of $90 million to $150 million in each of the next five years, with aggregate estimated contributions of $580 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 expense.

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three months ended March 31, 2012, and 2011:

 

     Pension  Benefits(a)     Postretirement  Benefits(a)  
     Three Months     Three Months  
     2012     2011     2012     2011  

Service cost

    $ 21      $ 20      $ 6      $ 6   

Interest cost

      43        45        14        15   

Expected return on plan assets

      (54 )      (54 )      (14 )      (14 ) 

Amortization of:

         

Prior service cost (benefit)

     —          —          (1 )      (2 ) 

Actuarial loss

     20        11        4        1   
  

 

 

    

 

 

    

 

 

    

 

 

  

Net periodic benefit cost

    $ 30      $ 22      $ 9      $ 6   
  

 

 

    

 

 

    

 

 

    

 

 

  

 

(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 months ended March 31, 2012, and 2011:

 

     Pension Costs      Postretirement Costs  
     Three Months      Three Months  
     2012      2011      2012      2011  

Ameren Missouri

    $ 16       $ 14       $ 5       $ 3   

Ameren Illinois

      10         5         2         2   

Genco

      3         2         2         1   

Other

      1         1         —           —     
  

 

 

     

 

 

     

 

 

     

 

 

  

Ameren(a)

   $ 30       $ 22       $ 9       $ 6   
  

 

 

     

 

 

     

 

 

     

 

 

  

 

(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 expense or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2011, its estimated investment performance through March 31, 2012, and its pension funding policy, Ameren expects to make annual contributions of $90 million to $150 million in each of the next five years, with aggregate estimated contributions of $580 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 expense.

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three months ended March 31, 2012, and 2011:

 

     Pension  Benefits(a)     Postretirement  Benefits(a)  
     Three Months     Three Months  
     2012     2011     2012     2011  

Service cost

    $ 21      $ 20      $ 6      $ 6   

Interest cost

      43        45        14        15   

Expected return on plan assets

      (54 )      (54 )      (14 )      (14 ) 

Amortization of:

         

Prior service cost (benefit)

     —          —          (1 )      (2 ) 

Actuarial loss

     20        11        4        1   
  

 

 

    

 

 

    

 

 

    

 

 

  

Net periodic benefit cost

    $ 30      $ 22      $ 9      $ 6   
  

 

 

    

 

 

    

 

 

    

 

 

  

 

(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 months ended March 31, 2012, and 2011:

 

     Pension Costs      Postretirement Costs  
     Three Months      Three Months  
     2012      2011      2012      2011  

Ameren Missouri

    $ 16       $ 14       $ 5       $ 3   

Ameren Illinois

      10         5         2         2   

Genco

      3         2         2         1   

Other

      1         1         —           —     
  

 

 

     

 

 

     

 

 

     

 

 

  

Ameren(a)

   $ 30       $ 22       $ 9       $ 6   
  

 

 

     

 

 

     

 

 

     

 

 

  

 

(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 expense or the legally required minimum contribution. Considering Ameren's assumptions at December 31, 2011, its estimated investment performance through March 31, 2012, and its pension funding policy, Ameren expects to make annual contributions of $90 million to $150 million in each of the next five years, with aggregate estimated contributions of $580 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 expense.

The following table presents the components of the net periodic benefit cost for Ameren's pension and postretirement benefit plans for the three months ended March 31, 2012, and 2011:

 

     Pension  Benefits(a)     Postretirement  Benefits(a)  
     Three Months     Three Months  
     2012     2011     2012     2011  

Service cost

    $ 21      $ 20      $ 6      $ 6   

Interest cost

      43        45        14        15   

Expected return on plan assets

      (54 )      (54 )      (14 )      (14 ) 

Amortization of:

         

Prior service cost (benefit)

     —          —          (1 )      (2 ) 

Actuarial loss

     20        11        4        1   
  

 

 

    

 

 

    

 

 

    

 

 

  

Net periodic benefit cost

    $ 30      $ 22      $ 9      $ 6   
  

 

 

    

 

 

    

 

 

    

 

 

  

 

(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 months ended March 31, 2012, and 2011:

 

     Pension Costs      Postretirement Costs  
     Three Months      Three Months  
     2012      2011      2012      2011  

Ameren Missouri

    $ 16       $ 14       $ 5       $ 3   

Ameren Illinois

      10         5         2         2   

Genco

      3         2         2         1   

Other

      1         1         —           —     
  

 

 

     

 

 

     

 

 

     

 

 

  

Ameren(a)

   $ 30       $ 22       $ 9       $ 6   
  

 

 

     

 

 

     

 

 

     

 

 

  

 

(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 and Ameren Missouri includes all the operations of Ameren Missouri's business as described in Note 1 - Summary of Significant Accounting Policies. The Ameren Illinois segment for Ameren and Ameren Illinois includes all of the operations of Ameren Illinois' business as described in Note 1 - Summary of Significant Accounting Policies. The Merchant Generation segment for Ameren consists primarily of the operations or activities of Genco, including EEI, AERG, Medina Valley through February 2012, 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 months ended March 31, 2012, and 2011, and total assets as of March 31, 2012, and December 31, 2011.

 

Three Months    Ameren
Missouri		      Ameren
Illinois		      Merchant
Generation		     Other     Intersegment
Eliminations		     Consolidated  

2012:

               

External revenues

    $ 686       $ 721       $ 249      $ 1      $ 1      $ 1,658   

Intersegment revenues

      5         3         87        1        (96 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      21         27         (363 )      (88 )      -        (403 ) 

2011:

               

External revenues

    $ 767       $ 805       $ 332      $ -      $ -      $ 1,904   

Intersegment revenues

      5         3         47        1        (56 )      -   

Net income (loss) attributable to Ameren Corporation(a)

      21         33         20        (3 )      -        71   

As of March 31, 2012:

               

Total assets

    $ 12,546       $ 7,256       $ 3,266      $ 1,261      $ (1,430 )    $ 22,899   

As of December 31, 2011:

               

Total assets

    $ 12,757       $ 7,213       $ 3,833      $ 1,211      $ (1,369 )    $ 23,645   

 

(a) Represents net income (loss) available to common stockholders.
Summary Of Significant Accounting Policies (Policy)
General 

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.

 

  •  

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

 

  •  

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

 

  •  

AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company. Genco operates a merchant electric generation business in Illinois and holds an 80% ownership interest in EEI, which it consolidates for financial reporting purposes.

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

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

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

Earnings Per Share 

Earnings Per Share

There were no material differences between Ameren's basic and diluted earnings per share amounts for the three months ended March 31, 2012, and 2011. In the first quarter of 2012, potential issuances of common shares related to stock-based compensation plans were excluded from the quarterly diluted earnings per share calculation because the effect was antidilutive. In 2011, the number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share.

Stock-based Compensation 

Stock-based Compensation

A summary of nonvested shares as of March 31, 2012, and changes during the three months ended March 31, 2012, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) is presented below:

 

      Performance Share Units  
      Share Units    

Weighted-average Fair Value
Per Unit

at Grant Date

  

Nonvested at January 1, 2012

      1,156,831      $ 31.70   

Granted(a)

      717,151        35.68   

Forfeitures

      (3,897 )      32.94   

Vested(b)

      (110,729 )      35.68   

Nonvested at March 31, 2012

      1,759,356      $ 33.07   

 

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b) Share units vested due to 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 2012 under the 2006 Plan was determined to be $35.68. That amount was based on Ameren's closing common share price of $33.13 at December 31, 2011, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren's total shareholder return for a three-year performance period relative to the designated peer group beginning January 1, 2012. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.41%, volatility of 17% to 31% for the peer group, and Ameren's attainment of a three-year average earnings per share threshold during the performance period.

Ameren recorded compensation expense of $6 million and a related tax benefit of $2 million for both the three months ended March 31, 2012, and 2011. There were no significant compensation costs capitalized related to the performance share units during the three months ended March 31, 2012, and 2011. As of March 31, 2012, total compensation cost of $32 million related to nonvested awards not yet recognized was expected to be recognized over a weighted-average period of 26 months.

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 March 31, 2012, Ameren's and Ameren Illinois' goodwill related to Ameren's acquisition of IP in 2004 and 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.

 

At March 31, 2012, Ameren's and Ameren Missouri's intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of each of Ameren's and Ameren Missouri's renewable energy credits was $9 million at March 31, 2012. The book value of each of Ameren's, Ameren Missouri's, and Genco's CAIR emission allowances was immaterial at March 31, 2012.

Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. The amortization expense based on usage of renewable energy credits and emission allowances was less than $1 million for Ameren, Ameren Missouri, Ameren Illinois, and Genco for the three months ended March 31, 2012, and $2 million, $1 million, and $1 million for Ameren, Ameren Illinois, and Genco, respectively, for the three months ended March 31, 2011. Amortization expense based on Ameren Missouri's usage of renewable energy credits was deferred as a regulatory asset pending recovery from customers through rates.

Excise Taxes 

Excise Taxes

Excise taxes imposed on us are reflected on Ameren Missouri electric and Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in "Taxes accrued" on the balance sheet. The following table presents excise taxes recorded in "Operating Revenues - Electric," "Operating Revenues - Gas" and "Operating Expenses - Taxes other than income taxes" for the three months ended March 31, 2012, and 2011:

 

XXXXXX XXXXXX
      Three Months  
      2012      2011  

Ameren Missouri

    $ 27       $ 29   

Ameren Illinois

      18         22   

Ameren

    $ 45       $ 51   
Uncertain Tax Positions 

Uncertain Tax Positions

The amount of unrecognized tax benefits as of March 31, 2012, was $150 million, $125 million, $11 million, and $10 million for Ameren, Ameren Missouri, Ameren Illinois and Genco, respectively. The amount of unrecognized tax benefits (detriments) as of March 31, 2012, that would impact the effective tax rate, if recognized, was $1 million, $1 million, $(1) million and $1 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. Ameren's federal income tax return for the year 2010 is currently under examination. In April 2012, Ameren filed a protest to the Appeals Office of the Internal Revenue Service with respect to certain adjustments proposed as a result of the Internal Revenue Service's audit examination of its 2010 federal income tax return.

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 expected that a partial settlement will be reached with the Appeals Office of the Internal Revenue Service in the next twelve months for the years 2007 through 2009 that would result in a decrease in uncertain tax liabilities. In addition, it is reasonably possible that events will occur during the next twelve 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 

Asset Retirement Obligations

AROs at Ameren, Ameren Missouri, Ameren Illinois and Genco increased compared to December 31, 2011, to reflect the accretion of obligations to their fair values. In addition, Ameren and Genco recorded an additional ARO in the amount of $1 million related to the retirement costs for a Genco coal combustion byproduct storage area during the three months ended March 31, 2012.

Noncontrolling Interest 

Noncontrolling Interest

Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity 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 interest at Ameren and Genco for the three months ended March 31, 2012, and 2011, is shown below:

 

XXXXXXX XXXXXXX
      Three Months  
      2012     2011  

Ameren:

     

Noncontrolling interest, beginning of period

    $ 149      $ 154   

Net income attributable to noncontrolling interest

      -        3   

Dividends paid to noncontrolling interest holders

      (2 )      (2 ) 

Noncontrolling interest, end of period

    $ 147      $ 155   

Genco:

     

Noncontrolling interest, beginning of period

    $ 7      $ 11   

Net income (loss) attributable to noncontrolling interest

      (2 )      1   

Noncontrolling interest, end of period

    $ 5      $ 12   
Summary Of Significant Accounting Policies (Tables)
Summary Of Nonvested Shares 
      Performance Share Units  
      Share Units    

Weighted-average Fair Value
Per Unit

at Grant Date

  

Nonvested at January 1, 2012

      1,156,831      $ 31.70   

Granted(a)

      717,151        35.68   

Forfeitures

      (3,897 )      32.94   

Vested(b)

      (110,729 )      35.68   

Nonvested at March 31, 2012

      1,759,356      $ 33.07   

 

(a) Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan.
(b) Share units vested due to 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 Excise Taxes 
XXXXXX XXXXXX
      Three Months  
      2012      2011  

Ameren Missouri

    $ 27       $ 29   

Ameren Illinois

      18         22   

Ameren

    $ 45       $ 51   
Schedule Of Equity Changes To The Noncontrolling Interest 
XXXXXXX XXXXXXX
      Three Months  
      2012     2011  

Ameren:

     

Noncontrolling interest, beginning of period

    $ 149      $ 154   

Net income attributable to noncontrolling interest

      -        3   

Dividends paid to noncontrolling interest holders

      (2 )      (2 ) 

Noncontrolling interest, end of period

    $ 147      $ 155   

Genco:

     

Noncontrolling interest, beginning of period

    $ 7      $ 11   

Net income (loss) attributable to noncontrolling interest

      (2 )      1   

Noncontrolling interest, end of period

    $ 5      $ 12   
Other Income And Expenses (Tables)
Other Income And Expenses
     Three Months  
     2012      2011  

Ameren:(a)

     

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 9       $ 6   

Interest income on industrial development revenue bonds

      7         7   

Interest and dividend income

      —           1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 17       $ 16   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 12       $ 2   

Other

      3         3   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 15       $ 5   
  

 

 

     

 

 

  

Ameren Missouri:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 8       $ 6   

Interest income on industrial development revenue bonds

      7         7   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 15       $ 13   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations

    $ 2       $ 1   

Other

      1         2   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 3       $ 3   
  

 

 

     

 

 

  

Ameren Illinois:

      

Miscellaneous income:

      

Allowance for equity funds used during construction

    $ 1       $ —     

Interest and dividend income

      —           1   

Other

      —           1   
  

 

 

     

 

 

  

Total miscellaneous income

    $ 1       $ 2   
  

 

 

     

 

 

  

Miscellaneous expense:

      

Donations(b)

   $ 10       $ —     

Other

      1         1   
  

 

 

     

 

 

  

Total miscellaneous expense

    $ 11       $ 1   
  

 

 

     

 

 

  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' participation in the formula ratemaking process.
Derivative Financial Instruments (Tables)
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)		  
     2012     2011     2012     2011     2012     2011     2012     2011  

Coal (in tons)

                                                                 

Ameren Missouri

                      111                        116                        (e )                      (e )                      (e )                      (e )                      (e )                      (e ) 

Genco

      22        24        (e )      (e )      3        (e )      (e )      (e ) 

Other(f)

      7        7        (e )      (e )      1        (e )      (e )      (e ) 

Ameren

      140        147        (e )      (e )      4        (e )      (e )      (e ) 

Fuel oils (in gallons)(g)

                                                                 

Ameren Missouri

      (e )      (e )      (e )      (e )      (e )      (e )      45        53   

Genco

      (e )      (e )      (e )      (e )      39        27        (e )      (e ) 

Other(f)

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

Ameren

      (e )      (e )      (e )      (e )      51        36        45        53   

Natural gas (in mmbtu)

                                                                 

Ameren Missouri

      7        8        (e )      (e )      14        9        22        19   

Ameren Illinois

      34        42        (e )      (e )      (e )      (e )      163        174   

Genco

      (e )      (e )      (e )      (e )      5        7        (e )      (e ) 

Other(f)

      (e )      (e )      (e )      (e )      1        1        (e )      (e ) 

Ameren

      41        50        (e )      (e )      20        17        185        193   

Power (in megawatthours)

                                                                 

Ameren Missouri

      1        1        (e )      (e )      1        1        12        6   

Ameren Illinois

      23        11        (e )      (e )      (e )      (e )      21        24   

Genco

      (e )      (e )      (e )      (e )      -        -        (e )      (e ) 

Other(f)

      66        61        19        17        43        30        (7 )      (9 ) 

Ameren

      90        73        19        17        44        31        26        21   

Uranium (pounds in thousands)

                                                                 

Ameren Missouri & Ameren

      5,553        5,553        (e )      (e )      (e )      (e )      148        148   

 

(a) Contracts through December 2017, March 2015, September 2035, and October 2024 for coal, natural gas, power, and uranium, respectively, as of March 31, 2012.
(b) Contracts through December 2016 for power as of March 31, 2012.
(c) Contracts through December 2014, October 2015, January 2013, and November 2016 for coal, fuel oils, natural gas, and power, respectively, as of March 31, 2012.
(d) Contracts through October 2014, October 2016, May 2032, and December 2013 for fuel oils, natural gas, power, and uranium, respectively, as of March 31, 2012.
(e) Not applicable.
(f) Includes AERG contracts for coal and fuel oils, Marketing Company contracts for natural gas and power, and intercompany eliminations for power.
(g) Fuel oils consist of heating and crude oil.
Derivative Instruments Carrying Value 
                                     
      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

2012:

                                 

Derivative assets designated as hedging instruments

                                 

Commodity contracts:

                                      

Power

    MTM derivative assets    $ 19      $ -      $ (b )    $ -   
    

Other assets

      30        -        -        -   
    

Total assets

    $ 49      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                 

Commodity contracts:

                                      

Power

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

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Fuel oils

    MTM derivative assets    $ 36      $ 22      $ (b )    $ 11   
    

Other assets

      9        5        -        2   

Natural gas

    MTM derivative assets      5        2        (b )      2   
    

Other current assets

      -        -        1        -   
    

Other assets

      1        -        -        -   

Power

    MTM derivative assets      107        35        (b )      -   
    

Other assets

      29        -        -        -   
    

Total assets

    $ 187      $ 64      $ 1      $ 15   

Derivative liabilities not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Coal

    MTM derivative liabilities    $ 2      $ (b )    $ -      $  (b ) 
    

Other current liabilities

      -        -        -        1   
    

Other deferred credits and liabilities

      2        -        -        2   

Fuel oils

    Other deferred credits and liabilities      1        1        -        -   

Natural gas

    MTM derivative liabilities      120        (b )      102        (b ) 
    

Other current liabilities

      -        15        -        1   
    

Other deferred credits and liabilities

      95        13        82        -   

Power

    MTM derivative liabilities      97        (b )      20        (b ) 
    

MTM derivative liabilities - affiliates

      (b )      (b )      183        (b ) 
    

Other current liabilities

      -        15        -        -   
    

Other deferred credits and liabilities

      112        -        81        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 430      $ 45      $ 468      $ 4   

2011:

                                      

Derivative assets designated as hedging instruments

                                 

Commodity contracts:

                                      

Power

    MTM derivative assets    $ 8      $ -      $ (b )    $ -   
    

Other assets

      16        -        -        -   
    

Total assets

    $ 24      $ -      $ -      $ -   

Derivative liabilities designated as hedging instruments

                                

Commodity contracts:

                                      

Power

    Other deferred credits and liabilities    $ 1      $ -      $ -      $ -   
    

Total liabilities

    $ 1      $ -      $ -      $ -   

Derivative assets not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Fuel oils

    MTM derivative assets    $ 29      $ 17      $ (b )    $ 10   
    

Other assets

      8        6        -        1   

 

                                     
      Balance Sheet Location   

Ameren(a)

     Ameren Missouri     Ameren Illinois     Genco  

Natural gas

    MTM derivative assets      6        2        (b )      2   
    

Other current assets

      -        -        1        -   
    

Other assets

      -        -        1        -   

Power

    MTM derivative assets      72        30        (b )      -   
    

Other assets

      99        -        77        -   
    

Total assets

    $ 214      $ 55      $ 79      $ 13   

Derivative liabilities not designated as hedging instruments(c)

                                 

Commodity contracts:

                                      

Fuel oils

    MTM derivative liabilities    $ 2      $ (b )    $ -      $ (b ) 
    

Other current liabilities

      -        1        -        1   

Natural gas

    MTM derivative liabilities      106        (b )      90        (b ) 
    

Other current liabilities

      -        13        -        2   
    

Other deferred credits and liabilities

      92        13        79        -   

Power

    MTM derivative liabilities      53        (b )      9        (b ) 
    

MTM derivative liabilities - affiliates

      (b )      (b )      200        (b ) 
    

Other current liabilities

      -        9        -        -   
    

Other deferred credits and liabilities

      26        -        8        -   

Uranium

    Other deferred credits and liabilities      1        1        -        -   
    

Total liabilities

    $ 280      $ 37      $ 386      $ 3   

 

(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 In OCI 
                                         
      Ameren     Ameren Missouri     Ameren Illinois     Genco     Other(a)  

2012:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 41      $ -      $ -      $ -      $ 41   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

                                         

Fuel oils derivative contracts(e)

      24        24        -        -        -   

Natural gas derivative contracts(f)

      (209 )      (26 )      (183 )      -        -   

Power derivative contracts(g)

      (81 )      20        (284 )      -        183   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

2011:

                                         

Cumulative gains (losses) deferred in accumulated OCI:

                                         

Power derivative contracts(b)

    $ 19      $ -      $ -      $ -      $ 19   

Interest rate derivative contracts(c)(d)

     (8 )      -        -        (8 )      -   

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

                                         

Fuel oils derivative contracts(e)

      19        19        -        -        -   

Natural gas derivative contracts(f)

      (191 )      (24 )      (167 )      -        -   

Power derivative contracts(g)

      81        21        (140 )      -        200   

Uranium derivative contracts(h)

      (1 )      (1 )      -        -        -   

 

(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 2016 as of March 31, 2012. Current gains of $14 million and $5 million were recorded at Ameren as of March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, 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 March 31, 2012, and December 31, 2011, was a loss of $8 million and $9 million, respectively. Over the next twelve months, $1.4 million of the loss will be amortized.
(e) Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through October 2014 as of March 31, 2012. Current gains deferred as regulatory liabilities include $20 million and $20 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current gains deferred as regulatory liabilities include $16 million and $16 million at Ameren and Ameren Missouri as of December 31, 2011, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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 March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $115 million, $13 million, and $102 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $101 million, $11 million, and $90 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.

(g) Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of March 31, 2012. Current gains deferred as regulatory liabilities include $34 million and $34 million at Ameren and Ameren Missouri, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $32 million, $13 million, and $203 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $17 million, $8 million, and $209 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.
(h) Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of our uranium requirements through December 2013 as of March 31, 2012. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of December 31, 2011, respectively.
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  

2012:

                                                                                 

AMO

    $ 1       $ -       $ 1       $ 9       $ 35       $ 4       $ -       $ -       $ 50    

AIC

      -         -         2         1         1         -         4         -         8    

Genco

      -         -         -         -         8         -         2         -         10    

Other(b)

      266         -         2         20         74         461         2         111         936    

Ameren

    $ 267       $ -       $ 5       $ 30       $ 118       $ 465       $ 8       $ 111       $     1,004    

2011:

                                                                                 

AMO

    $ 1       $ 35       $ 1       $ 4       $ 26       $ 4       $ -       $ -       $ 71    

AIC

      -         -         84         -         1         -         -         -         85    

Genco

      -         1         1         2         6         -         3         -         13    

Other(b)

      275         1         3         10         51         194         -         87         621    

Ameren

    $ 276       $ 37       $ 89       $ 16       $ 84       $ 198       $ 3       $ 87       $ 790    

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in the Form 10-K for additional information on these financial contracts.
(b) Includes amounts for Marketing Company, AERG, and AFS.
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  

2012:

                                                                                 

AMO

    $ 1       $ -       $ 1       $ 4       $ 28       $ 4       $ -       $ -       $ 38   

AIC

      -         -         2         -         -         -         -         -         2   

Genco

      -         -         -         -         3         -         -         -         3   

Other(b)

      266         -         1         9         67         455         2         110         910   

Ameren

    $ 267       $ -       $ 4       $ 13       $ 98       $ 459       $ 2       $ 110       $     953   

2011:

                                                                                 

AMO

    $ 1       $ 35       $ 1       $ 3       $ 22       $ 4       $ -       $ -       $ 66   

AIC

      -         -         84         -         -         -         -         -         84   

Genco

      -         -         -         1         1         -         2         -         4   

Other(b)

      273         -         3         5         42         187         -         86         596   

Ameren

    $ 274       $ 35       $ 88       $ 9       $ 65       $ 191       $ 2       $ 86       $ 750   

 

(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 for purposes of this disclosure, as it is calculated without regard to the offsetting affiliate counterparty's liability position. See Note 14-Related Party Transactions in 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)

  

2012:

                           

Ameren Missouri

      $                    128         $                    8         $                    142   

Ameren Illinois

      223         109         111   

Genco

      57         -         61   

Other(c)

      82         12         66   

Ameren

      $                    490         $                129         $                    380   

2011:

                           

Ameren Missouri

      $                    102         $                    8         $                      86   

Ameren Illinois

      220         96         125   

Genco

      55         1         58   

Other(c)

      79         11         63   

Ameren

      $                     456         $                116         $                     332   

 

(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)

  

2012:

                                   

Ameren:(d)

                                   

Power

    $ 18      Operating Revenues - Electric    $ 4      Operating Revenues - Electric    $ 2   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

Genco:

                                   

Interest rate(e)

      -      Interest Charges      (f )    Interest Charges      -   

2011:

                                   

Ameren:(d)

                                   

Power

    $ (4 )    Operating Revenues - Electric    $ 1      Operating Revenues - Electric    $ (1 ) 

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

  
               2012     2011  
Ameren(a)    Coal    Operating Expenses - Fuel    $ (4 )    $ -   
     Fuel oils    Operating Expenses - Fuel      5        19   
     Natural gas (generation)    Operating Expenses - Fuel      1        -   
     Power    Operating Revenues - Electric      (1 )      (2 ) 
          Total    $ 1      $ 17   
Ameren Missouri    Natural gas (generation)    Operating Expenses - Fuel    $ -      $ (1 ) 
Genco    Coal    Operating Expenses - Fuel    $ (3 )    $ -   
     Fuel oils    Operating Expenses - Fuel      4        15   
          Total    $ 1      $ 15   

 

(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		  
            2012     2011  

Ameren(a)

    Fuel oils    $ 5      $ 29   
    

Natural gas

      (18 )      31   
    

Power

      (162 )      2   
    

Uranium

      -        (1 ) 
    

Total

    $ (175 )    $ 61   

Ameren

    Fuel oils    $ 5      $ 29   

Missouri

    Natural gas      (2 )      3   
    

Power

      (1 )      -   
    

Uranium

      -        (1 ) 
    

Total

    $ 2      $ 31   

Ameren Illinois

    Natural gas    $ (16 )    $ 28   
     Power      (144 )      27   
    

Total

    $ (160 )    $ 55   
(a) Includes amounts for intercompany eliminations.
Fair Value Measurements (Tables)
Schedule of Valuation Process And Unobservable Inputs 
            Fair Value      Valuation Technique(s)    Unobservable Input   

Range [Weighted

Average]

Level 3 Derivative assets - commodity contracts(b):

Ameren(a)

    Fuel oils    $ 9       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [1%]
  

Power(e)

      170       Option model    Volatilities(d)    15% - 68% [19%]
            Average bid/ask consensus pricing(d)    $16/MWh-$39/MWh [$35/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$29/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$173/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 13% [5%]

Ameren

Missouri

    Fuel oils    $ 7       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    23% - 28% [25%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 4% [1%]
  

Power(e)

      28       Option model    Volatilities(d)    40% - 68% [61%]
            Average bid/ask consensus pricing(d)    $16/MWh - $31/MWh [$19/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $17/MWh - $49/MWh [$23/MWh]
         FTR third party pricing    Estimated auction price(c)    $(1,569)/MW - $3,019/MW [$170/MW]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Counterparty credit risk(d)    0.06% - 12% [5%]

Genco

    Fuel oils    $ 2       Escalated exchange settled pricing    Escalation rate(c)    0.68% - 0.71% [0.71%]
         Option model    Volatilities(c)    25% - 28% [26%]
         Credit risk discount    Counterparty credit risk(d)    0.12% - 12% [2%]

Level 3 Derivative liabilities - commodity contracts(b):

Ameren(a)

    Power(e)    $ 194       Option model    Volatilities(d)    15% - 40% [24%]
            Average bid/ask consensus pricing(d)    $16/MWh - $39/MWh [$34/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$28/MWh]

 

            Fair Value      Valuation
Technique(s)		    Unobservable Input   

Range [Weighted

Average]

         Basis to nodal valuation price    Nodal basis(c)    $(6)/MWh - $(0.20)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
         Credit risk discount    Ameren credit risk(d)    3% - 6% [6%]
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren

Missouri

    Power(e)    $ 8       Option model    Volatilities(d)    35% - 40% [37%]
            Average bid/ask consensus pricing(d)    $16/MWh - $27/MWh [$23/MWh]
         Power forwards/swaps third party pricing    Average bid/ask consensus pricing(d)    $20/MWh - $49/MWh [$27/MWh]
         Basis to nodal valuation price    Nodal basis(c)    $(3)/MWh - $(0.48)/MWh [$(2)/MWh]
         Credit risk discount    Ameren Missouri credit risk(d)    3%
    

Uranium

      1       Third party pricing    Average bid/ask consensus pricing(c)    $51/pound - $55/pound [$52/pound]

Ameren Illinois

    Power(e)    $ 284       Power forwards/swaps third party pricing    Average bid/ask consensus pricing(c)    $20/MWh - $36/MWh $[28/MWh]
         Basis to nodal valuation price    Nodal basis(d)    $(4)/MWh - $(1)/MWh [$(3)/MWh]
         Power market simulation model    Estimated future gas prices(c)    $4/mmbtu - $6/mmbtu [$5/mmbtu]
         Contract price allocation    Estimated renewable energy credit costs(c)    $5/credit - $7/credit [$6/credit]
                   Credit risk discount    Ameren Illinois credit risk(d)    6%

 

(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) Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(d) Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement.
(e) Power valuations utilize visible third party pricing evaluated by month for peak and off-peak through 2015. Valuations beyond 2015 utilize power market simulation modeled pricing by month for peak and off-peak.
Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis 
           

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):

            
  

Fuel oils

    $ 36       $ -       $ 9       $ 45   
  

Natural gas

      4         2         -         6   
  

Power

      -         15         170         185   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Missouri

   

Fuel oils

      20         -         7         27   
  

Natural gas

      2         -         -         2   
  

Power

      -         7         28         35   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      264         -         -         264   
  

Debt securities:

            
  

Corporate bonds

      -         46         -         46   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         66         -         66   
  

Asset-backed securities

      -         10         -         10   
  

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

                                    

Illinois

   

Natural gas

      -         1         -         1   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      11         -         2         13   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

    $ 4       $ -       $ -       $ 4   
  

Fuel oils

      1         -         -         1   
  

Natural gas

      19         196         -         215   
  

Power

      -         16         194         210   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         16         -         28   
  

Power

      -         7         8         15   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      5         179         -         184   
    

Power

      -         -         284         284   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Coal

      3         -         -         3   
    

Natural gas

      1         -         -         1   

 

(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, 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):

            
  

Fuel oils

    $ 33       $ -       $ 4       $ 37   
  

Natural gas

      4         -         2         6   
  

Power

      -         2         193         195   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Missouri

   

Fuel oils

      20         -         3         23   
  

Natural gas

      2         -         -         2   
  

Power

      -         1         29         30   
  

Nuclear Decommissioning Trust Fund(c):

            
  

Cash and cash equivalents

      3         -         -         3   
  

Equity securities:

            
  

U.S. large capitalization

      234         -         -         234   
  

Debt securities:

            
  

Corporate bonds

      -         44         -         44   
  

Municipal bonds

      -         1         -         1   
  

U.S. treasury and agency securities

      -         65         -         65   
  

Asset-backed securities

      -         10         -         10   
    

Other

      -         1         -         1   

Ameren

   

Derivative assets - commodity contracts(b):

            

Illinois

   

Natural gas

      -         -         2         2   
    

Power

      -         -         77         77   

Genco

   

Derivative assets - commodity contracts(b):

            
  

Fuel oils

      10         -         1         11   
    

Natural gas

      2         -         -         2   

Liabilities:

               

Ameren(a)

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

    $ 2       $ -       $ -       $ 2   
  

Natural gas

      22         -         176         198   
  

Power

      -         2         78         80   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Missouri

   

Fuel oils

      1         -         -         1   
  

Natural gas

      12         -         14         26   
  

Power

      -         1         8         9   
    

Uranium

      -         -         1         1   

Ameren

   

Derivative liabilities - commodity contracts(b):

            

Illinois

   

Natural gas

      7         -         162         169   
    

Power

      -         -         217         217   

Genco

   

Derivative liabilities - commodity contracts(b):

            
  

Fuel oils

      1         -         -         1   
    

Natural gas

      2         -         -         2   

 

(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 
      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2012

    $ 3      $ (a )    $ 1      $ —        $ 4   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      2        -        2   

Included in regulatory assets/liabilities

      2        (a )      (a )      (a )      2   

Total realized and unrealized gains (losses)

      2        (a )      2        -        4   

Transfers into Level 3

      2        (a )      -        -        2   

Transfers out of Level 3

      -        (a )      (1 )      -        (1 ) 

Ending balance at March 31, 2012

    $ 7      $ (a )    $ 2      $        $ 9   

Change in unrealized gains (losses) related to assets/liabilities held at March 31,2012

    $ 2      $ (a )    $ 1      $        $ 3   

Natural gas:

           

Beginning balance at January 1, 2012

    $ (14 )    $ (160 )    $ -      $ -      $ (174 ) 

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      (2 )      (26 )      (a )      (a )      (28 ) 

Total realized and unrealized gains (losses)

      (2 )      (26 )      (a )      (a )      (28 ) 

Settlements

      1        16        -        -        17   

Transfer out of Level 3

      15        170        -        -        185   

Ending balance at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ -      $ -      $ -      $ -      $ -   

Power:

           

Beginning balance at January 1, 2012

    $ 21      $ (140 )    $ -      $ 234      $ 115   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        8        8   

Included in OCI

      -        -        -        24        24   

Included in regulatory assets/liabilities

      13        (220 )      (a )      49        (158 ) 

Total realized and unrealized gains (losses)

      13        (220 )      -        81        (126 ) 

Purchases

      -        -        -        (1 )      (1 ) 

Sales

      -        -        -        1        1   

Settlements

      (13 )      76        -        (77 )      (14 ) 

Transfers out of Level 3

      (1 )      -        -        2        1   

Ending balance at March 31, 2012

    $ 20      $ (284 )    $ -      $ 240      $ (24 ) 

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

    $ 10      $ (202 )(d)    $ -      $ 59      $ (133 ) 

Uranium:

           

Beginning balance at January 1, 2012

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        (a )      (a )      (a )      -   

Total realized and unrealized gains (losses)

      -        (a )      (a )      (a )      -   

Ending balance at March 31, 2012

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2012

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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.
(d) The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois' swap contracts, which expire in May 2032.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of March 31, 2011:

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Fuel oils:

           

Beginning balance at January 1, 2011

    $ 30      $ (a )    $ 17      $ 4      $ 51   

Realized and unrealized gains (losses):

           

Included in earnings(b)

      -        (a )      15        7        22   

Included in regulatory assets/liabilities

      31        (a )      (a )      (a )      31   

Total realized and unrealized gains (losses)

      31        (a )      15        7        53   

Purchases

      1        (a )      -        -        1   

Settlements

      (5 )      (a )      (3 )      (1 )      (9 ) 

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 49      $ (a )    $ 16      $ 4      $ 69   

Natural gas:

           

Beginning balance at January 1, 2011

    $ (14 )    $ (134 )    $ -      $ -      $ (148 ) 

 

      Net derivative commodity contracts  
      Ameren
Missouri		     Ameren
Illinois		     Genco     Other(c)     Ameren  

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

      -        7        (a )      (a )      7   

Total realized and unrealized gains (losses)

      -        7        -        -        7   

Settlements

      2        19        -        -        21   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 1      $ 6      $ -      $ -      $ 7   

Power:

           

Beginning balance at January 1, 2011

    $ 2      $ (352 )    $ 3      $ 383      $ 36   

Realized and unrealized gains (losses):

           

Included in earnings(b)

     -        -        -        (3 )      (3 ) 

Included in OCI

      -        -        -        -        -   

Included in regulatory assets/liabilities

      7        (30 )      (a )      21        (2 ) 

Total realized and unrealized gains (losses)

      7        (30 )      -        18        (5 ) 

Purchases

      -        -        -        9        9   

Sales

      -        -        -        (9 )      (9 ) 

Settlements

      (6 )      57        -        (51 )      -   

Transfers into Level 3

      (1 )      -        -        1        -   

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

    $ 3      $ (25 )    $ -      $ 31      $ 9   

Uranium:

           

Beginning balance at January 1, 2011

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

Realized and unrealized gains (losses):

           

Included in regulatory assets/liabilities

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

Total realized and unrealized gains (losses)

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

Ending balance at March 31, 2011

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

Change in unrealized gains (losses) related to assets/liabilities held at March 31, 2011

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

 

(a) Not applicable.
(b) Net gains and losses on fuel oils 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 Transfers Between Fair Value Hierarchy Levels 
      2012     2011  

Ameren - derivative commodity contracts:(a)

     

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

    $   2      $   - 

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

      (1 )      -   

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

      185        -   

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

      1        -   

Net fair value of Level 3 transfers

    $   187      $ -   

 

      2012     2011  

Ameren Missouri - derivative commodity contracts:

     

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

    $ 2      $ -   

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

      15        -   

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

      -        (1 ) 

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

      (1 )      -   

Net fair value of Level 3 transfers

    $ 16      $ (1 ) 

Ameren Illinois - derivative commodity contracts:

     

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

    $ 170      $ -   

Genco - derivative commodity contracts:

     

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

    $ (1 )    $ -   

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt, Capital Lease Obligations And Preferred Stock 
      March 31, 2012      December 31, 2011  
      Carrying
Amount		      Fair
Value		      Carrying
Amount		      Fair
Value		  

Ameren:(a)(b)

            

Long-term debt and capital lease obligations (including current portion)

    $ 6,856       $   7,673       $ 6,856       $   7,800   

Preferred stock

      142         93         142         92   

Ameren Missouri:

            

Long-term debt and capital lease obligations (including current portion)

    $ 3,950       $ 4,530       $ 3,950       $ 4,541   

Preferred stock

      80         55         80         55   

Ameren Illinois:

            

Long-term debt (including current portion)

    $ 1,658       $ 1,967       $ 1,658       $ 1,943   

Preferred stock

      62         38         62         37   

Genco:

            

Long-term debt (including current portion)

    $ 824       $ 693       $ 824       $ 839   

 

(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)
Schedule Of Insurance Coverage At 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 industrywide 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 
      2012      2013 - 2016      2017 - 2021      Total  

AMO(a)

    $ 55       $ 325         -       $ 400       $
845
         -       $ 1,030       $ 1,225         -       $ 1,485   

Genco

      150         100         -         125         245         -         295         495         -         570   

AERG

      5         20         -         25         80         -         100         105         -         130   

Ameren

    $     210       $     445         -       $     550       $     1,170         -       $   1,425       $   1,825         -       $   2,185   

 

(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

    $   102       $   174       $ 102   

Ameren Missouri

      3         4         3   

Ameren Illinois

      99         170         99   

 

(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    Ameren Missouri    Ameren Illinois    Genco   Total(a)
4    59    81    (b)   101

 

(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 March 31, 2012, six 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.
Retirement Benefits (Tables)
Components Of Net Periodic Benefit Cost 
     Pension  Benefits(a)     Postretirement  Benefits(a)  
     Three Months     Three Months  
     2012     2011     2012     2011  

Service cost

    $ 21      $ 20      $ 6      $ 6   

Interest cost

      43        45        14        15   

Expected return on plan assets

      (54 )      (54 )      (14 )      (14 ) 

Amortization of:

         

Prior service cost (benefit)

     —          —          (1 )      (2 ) 

Actuarial loss

     20        11        4        1   
  

 

 

    

 

 

    

 

 

    

 

 

  

Net periodic benefit cost

    $ 30      $ 22      $ 9      $ 6   
  

 

 

    

 

 

    

 

 

    

 

 

  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Summary Of Benefit Plan Costs Incurred 
     Pension Costs      Postretirement Costs  
     Three Months      Three Months  
     2012      2011      2012      2011  

Ameren Missouri

    $ 16       $ 14       $ 5       $ 3   

Ameren Illinois

      10         5         2         2   

Genco

      3         2         2         1   

Other

      1         1         —           —     
  

 

 

     

 

 

     

 

 

     

 

 

  

Ameren(a)

   $ 30       $ 22       $ 9       $ 6   
  

 

 

     

 

 

     

 

 

     

 

 

  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
1 Months Ended 3 Months Ended 1 Months Ended
Jan. 31, 2012
Mar. 31, 2012
M
Mar. 31, 2011
Dec. 31, 2011
Feb. 29, 2012
Medina Valley Energy Center [Member]
Summary Of Significant Accounting Policies [Line Items]
 
 
 
 
 
Fair value of each share unit, per share
$ 35.68 
$ 35.68 1
 
 
 
Closing common share price
 
 
 
$ 33.13 
 
Three-year risk-free rate
 
0.41% 
 
 
 
Volatility rate, minimum
 
17.00% 
 
 
 
Volatility rate, maximum
 
31.00% 
 
 
 
Share-based compensation expense
 
$ 6 
$ 6 
 
 
Employee service share-based compensation, tax benefit from compensation expense
 
2 
2 
 
 
Compensation cost not yet recognized
 
32 
 
 
 
Expected weighted average recognition period for share-based compensation expense, in months
 
26 
 
 
 
Book value
 
9 
 
7 
 
Amortization expense
 
1 
2 
 
 
Unrecognized tax benefits
 
150 
 
 
 
Unrecognized tax benefits that would impact effective tax rate
 
1 
 
 
 
ARO Incurred
 
1 
 
 
 
Percentage of EEI not owned by Ameren
 
20.00% 
 
 
 
Proceeds from sales of properties
 
 
 
 
16 
Additional contingent proceeds from sale of properties
 
 
 
 
1 
Pretax gain recognized on sale
 
 
 
 
$ 10 
Summary Of Significant Accounting Policies (Summary Of Nonvested Shares) (Details) (USD $)
1 Months Ended 3 Months Ended
Jan. 31, 2012
Mar. 31, 2012
Summary Of Significant Accounting Policies [Abstract]
 
 
Share Units, Nonvested at January 1, 2012
1,156,831 
1,156,831 
Share Units, Granted
 
717,151 1
Share Units, Forfeited
 
(3,897)
Share Units, Vested
 
(110,729)2
Share Units, Nonvested at March 31, 2012
 
1,759,356 
Weighted-average Fair Value Per Unit, Nonvested at January 1, 2012
$ 31.70 
$ 31.70 
Weighted-average Fair Value Per Unit, Granted
$ 35.68 
$ 35.68 1
Weighted-average Fair Value Per Unit, Forfeitures
 
$ 32.94 
Weighted-average Fair Value Per Unit, Vested
 
$ 35.68 2
Weighted-average Fair Value Per Unit, Nonvested at March 31, 2012
 
$ 33.07 
Summary Of Significant Accounting Policies (Equity Changes Attributable To Noncontrolling Interest) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Summary Of Significant Accounting Policies [Abstract]
 
 
Noncontrolling interest, beginning of period
$ 149 
 
Net income attributable to noncontrolling interest
 
3 
Dividends paid to noncontrolling interest holders
(2)
(2)
Noncontrolling interest, end of period
$ 147 
 
Rate And Regulatory Matters (Narrative-Missouri) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 1 Months Ended 1 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Dec. 31, 2011
Dec. 31, 2010
Feb. 29, 2012
MoPSC Staff Report [Member]
FAC Prudence Review [Member]
Subsequent Periods After September 30, 2009 [Member]
Apr. 30, 2011
Ameren Missouri [Member]
FAC Prudence Review [Member]
Sep. 30, 2011
Ameren Missouri [Member]
FAC Prudence Review [Member]
M
Mar. 31, 2012
Ameren Missouri [Member]
2009 Final Rate Order [Member]
Electric Distribution [Member]
May 31, 2012
Ameren Missouri [Member]
Final Rate Order [Member]
Electric Distribution [Member]
Jul. 31, 2011
Ameren Missouri [Member]
Final Rate Order [Member]
Electric Distribution [Member]
May 31, 2010
Ameren Missouri [Member]
Final Rate Order [Member]
Electric Distribution [Member]
customer
Feb. 3, 2012
Ameren Missouri [Member]
Pending Rate Order [Member]
Electric Distribution [Member]
Jan. 31, 2012
Ameren Missouri [Member]
Pending Rate Order [Member]
MEEIA Filing [Member]
Electric Distribution [Member]
Jul. 31, 2011
Ameren Missouri [Member]
Accounting Authority Order Request [Member]
FAC Prudence Review [Member]
Rate And Regulatory Matters [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of industrial customers who received a stay from Circuit Court
 
 
 
 
 
 
 
 
 
 
4 
 
 
 
Amount held by Circuit Court based on appeal of electric rate order
 
 
 
 
 
 
 
 
$ 2 
 
$ 16 
 
 
 
Cash received
208 
573 
255 
545 
 
 
 
21 
14 
 
 
 
 
 
Authorized increase in revenue from utility service
 
 
 
 
 
 
 
 
 
173 
 
 
 
 
Utility revenue increase requested
 
 
 
 
 
 
 
 
 
 
 
376 
81 
 
Energy Efficiency program spending
 
 
 
 
 
 
 
 
 
 
 
 
145 
 
Number of years energy efficiency spending will occur
 
 
 
 
 
 
 
 
 
 
 
 
3 
 
Time required to complete FAC prudence reviews, in months
 
 
 
 
 
 
18 
 
 
 
 
 
 
 
Contested amounts under the FAC
 
 
 
 
26 
18 
 
 
 
 
 
 
 
 
Interest charges
113 
119 
 
 
 
1 
 
 
 
 
 
 
 
 
Request to defer fixed costs not recovered from Noranda, amount
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 36 
Rate And Regulatory Matters (Narrative-Illinois) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Mar. 31, 2012
Ameren Illinois Company [Member]
Dec. 31, 2011
Ameren Illinois Company [Member]
Mar. 31, 2012
IEIMA [Member]
Ameren Illinois Company [Member]
Apr. 30, 2012
Electric Distribution [Member]
IEIMA [Member]
Initial Filing [Member]
Ameren Illinois Company [Member]
Apr. 20, 2012
Electric Distribution [Member]
IEIMA [Member]
Update Filing [Member]
Ameren Illinois Company [Member]
Jan. 3, 2012
ICC Staff Recommendation [Member]
Electric Distribution [Member]
IEIMA [Member]
Initial Filing [Member]
Ameren Illinois Company [Member]
Utility revenue decrease requested
 
 
 
 
 
$ 19 
$ 15 
$ 25 
Regulatory assets
$ 1,657 
$ 1,603 
$ 814 
$ 748 
$ 12 
 
 
 
Rate And Regulatory Matters (Narrative-Federal) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Mar. 31, 2012
Ameren Illinois Company [Member]
Dec. 31, 2011
Ameren Illinois Company [Member]
Jan. 31, 2011
Wholesale Distribution Rate Case [Member]
Ameren Illinois Company [Member]
Mar. 31, 2012
New Nuclear Energy Center [Member]
Ameren Missouri [Member]
Utility revenue increase requested
 
 
 
 
$ 11 
 
Capitalized costs relating to construction of new nuclear unit
$ 17,535 
$ 18,127 
$ 4,804 
$ 4,770 
 
$ 69 
Short-Term Debt And Liquidity (Narrative) (Details) (USD $)
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Dec. 31, 2011
Line of Credit Facility [Line Items]
 
 
 
Actual debt-to-capital ratio
0.49 
 
 
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 
 
 
Multiyear Credit Facility [Member]
 
 
 
Line of Credit Facility [Line Items]
 
 
 
Maximum consolidated indebtedness as a percent of total capitalization
65.00% 
 
 
2010 Credit Agreements [Member] |
Multiyear Credit Facility [Member]
 
 
 
Line of Credit Facility [Line Items]
 
 
 
Line of credit facility, maximum borrowing capacity
$ 1,960,000,000 
 
 
Commercial Paper [Member]
 
 
 
Line of Credit Facility [Line Items]
 
 
 
Commercial paper outstanding
126,000,000 
 
148,000,000 
Average daily commercial paper borrowings outstanding
84,000,000 
321,000,000 
 
Weighted average interest rate
0.94% 
0.94% 
 
Peak short-term borrowings
$ 186,000,000 
$ 377,000,000 
 
Peak short-term borrowings interest rate
1.25% 
1.46% 
 
Long-Term Debt And Equity Financings (Narrative) (Details) (Senior Unsecured Notes 8.875% Due 2014 [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Senior Unsecured Notes 8.875% Due 2014 [Member]
 
Long-Term Debt And Equity Financings [Line Items]
 
Excess in indebtedness upon default of maturity
$ 25 
Other Income And Expenses (Other Income And Expenses) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Allowance for equity funds used during construction
$ 9 1
$ 6 1
Interest income on industrial development revenue bonds
7 1
7 1
Interest and dividend income
 
1 1
Other
1 1
2 1
Total miscellaneous income
17 1
16 1
Donations
12.0 1 2
2.0 1 2
Other
3 1
3 1
Total miscellaneous expense
15 1
5 1
Ameren Illinois Company [Member]
 
 
Total miscellaneous income
1 
2 
Total miscellaneous expense
11 
1 
Customer Assistance Programs [Member] |
Ameren Illinois Company [Member]
 
 
Donations
1.0 
 
One-Time Donation [Member] |
Illinois Science and Energy Innovation Trust [Member] |
Ameren Illinois Company [Member]
 
 
Donations
7.5 
 
Annual Donation [Member] |
Illinois Science and Energy Innovation Trust [Member] |
Ameren Illinois Company [Member]
 
 
Donations
$ 1.0 
 
Derivative Financial Instruments (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Derivative [Line Items]
 
 
Cash collateral held from counterparties
 
$ 1 
Counterparty letters of credit held as collateral
7 
9 
Ameren Missouri [Member]
 
 
Derivative [Line Items]
 
 
Cash collateral held from counterparties
2 
 
Marketing Company [Member]
 
 
Derivative [Line Items]
 
 
Cash collateral held from counterparties
$ 4 
 
Derivative Financial Instruments (Open Gross Derivative Volumes By Commodity Type) (Details)
Mar. 31, 2012
Dec. 31, 2011
Coal (In Tons) [Member]
 
 
Derivative [Line Items]
 
 
NPNS Contract
140,000,000 1
147,000,000 1
Cash Flow Hedges
   2 3
   2 3
Other Derivatives
4,000,000 4
   2 4
Derivatives That Qualify for Regulatory Deferral
   2 5
   5
Fuel Oils (In Gallons) [Member]
 
 
Derivative [Line Items]
 
 
NPNS Contract
   1 2 6
   1 2 6
Cash Flow Hedges
   2 3 6
   2 3 6
Other Derivatives
51,000,000 4 6
36,000,000 4 6
Derivatives That Qualify for Regulatory Deferral
45,000,000 5 6
53,000,000 5 6
Natural Gas (In Mmbtu) [Member]
 
 
Derivative [Line Items]
 
 
NPNS Contract
41,000,000 1
50,000,000 1
Cash Flow Hedges
   2 3
   2 3
Other Derivatives
20,000,000 4
17,000,000 4
Derivatives That Qualify for Regulatory Deferral
185,000,000 5
193,000,000 5
Power (In Megawatt Hours) [Member]
 
 
Derivative [Line Items]
 
 
NPNS Contract
90,000,000 1
73,000,000 1
Cash Flow Hedges
19,000,000 3
17,000,000 3
Other Derivatives
44,000,000 4
31,000,000 4
Derivatives That Qualify for Regulatory Deferral
26,000,000 5
21,000,000 5
Uranium (In Pounds) [Member]
 
 
Derivative [Line Items]
 
 
NPNS Contract
5,553,000 1
5,553,000 1
Cash Flow Hedges
   2 3
   2 3
Other Derivatives
   2 4
   2 4
Derivatives That Qualify for Regulatory Deferral
148,000 5
148,000 5
Derivative Financial Instruments (Derivative Instruments Carrying Value) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Designated As Hedging Instrument [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
$ 49 1
$ 24 1
Derivative liabilities used as hedging instruments
1 1
1 1
Designated As Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
19 1
8 1
Designated As Hedging Instrument [Member] |
Power [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
30 1
16 1
Designated As Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
1 1
 
Designated As Hedging Instrument [Member] |
Power [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
 
1 1
Not Designated As Hedging Instrument [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
187 1 2
214 1 2
Derivative liabilities used as hedging instruments
430 1 2
280 1 2
Not Designated As Hedging Instrument [Member] |
Coal [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
2 1 2
 
Not Designated As Hedging Instrument [Member] |
Coal [Member] |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
   1 2
 
Not Designated As Hedging Instrument [Member] |
Coal [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
2 1 2
 
Not Designated As Hedging Instrument [Member] |
Fuel Oils [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
36 1 2
29 1 2
Not Designated As Hedging Instrument [Member] |
Fuel Oils [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
9 1 2
8 1 2
Not Designated As Hedging Instrument [Member] |
Fuel Oils [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
 
2 1 2
Not Designated As Hedging Instrument [Member] |
Fuel Oils [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
1 1 2
 
Not Designated As Hedging Instrument [Member] |
Natural Gas [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
5 1 2
6 1 2
Not Designated As Hedging Instrument [Member] |
Natural Gas [Member] |
Other Current Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
   1 2
 
Not Designated As Hedging Instrument [Member] |
Natural Gas [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
1 1 2
 
Not Designated As Hedging Instrument [Member] |
Natural Gas [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
120 1 2
106 1 2
Not Designated As Hedging Instrument [Member] |
Natural Gas [Member] |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
   1 2
 
Not Designated As Hedging Instrument [Member] |
Natural Gas [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
95 1 2
92 1 2
Not Designated As Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
107 1 2
72 1 2
Not Designated As Hedging Instrument [Member] |
Power [Member] |
Other Assets [Member]
 
 
Derivative [Line Items]
 
 
Derivative assets used hedging instruments
29 1 2
99 1 2
Not Designated As Hedging Instrument [Member] |
Power [Member] |
Mark to Market Derivative Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
97 1 2
53 1 2
Not Designated As Hedging Instrument [Member] |
Power [Member] |
Other Current Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
   1 2
 
Not Designated As Hedging Instrument [Member] |
Power [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
112 1 2
26 1 2
Not Designated As Hedging Instrument [Member] |
Uranium [Member] |
Other Deferred Credits and Liabilities [Member]
 
 
Derivative [Line Items]
 
 
Derivative liabilities used as hedging instruments
$ 1 1 2
$ 1 1 2
Derivative Financial Instruments (Cumulative Amount Of Pretax Net Gains (Losses) On All Derivative Instruments In OCI) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2012
Dec. 31, 2011
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
$ 138 
$ 133 
Current losses deferred as regulatory assets
247 
215 
Power [Member]
 
 
Derivative [Line Items]
 
 
Gain (loss) to be amortized in next year
14.0 
5.0 
Current gains deferred as regulatory liabilities
34 
29 
Current losses deferred as regulatory assets
32 
17 
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
20 
16 
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Current gains deferred as regulatory liabilities
1 
1 
Current losses deferred as regulatory assets
115 
101 
Interest Rate Swap [Member]
 
 
Derivative [Line Items]
 
 
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
8 
9 
Accumulated Other Comprehensive Income (Loss) [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
41 1
19 1
Accumulated Other Comprehensive Income (Loss) [Member] |
Interest Rate Contract [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(8)2 3
(8)2 3
Regulatory Liabilities Or Assets [Member] |
Power [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(81)4
81 4
Regulatory Liabilities Or Assets [Member] |
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
24 5
19 5
Regulatory Liabilities Or Assets [Member] |
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
(209)6
(191)6
Regulatory Liabilities Or Assets [Member] |
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Cumulative deferred pretax gains (losses)
$ (1)7
$ (1)7
[4] Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of March 31, 2012. Current gains deferred as regulatory liabilities include $34 million and $34 million at Ameren and Ameren Missouri, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $32 million, $13 million, and $203 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $29 million and $29 million at Ameren and Ameren Missouri, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $17 million, $8 million, and $209 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.
[5] Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri's transportation costs for coal through October 2014 as of March 31, 2012. Current gains deferred as regulatory liabilities include $20 million and $20 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current losses deferred as regulatory assets include less than $1 million and less than $1 million at Ameren and Ameren Missouri as of March 31, 2012, respectively. Current gains deferred as regulatory liabilities include $16 million and $16 million at Ameren and Ameren Missouri as of December 31, 2011, respectively. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri as of December 31, 2011, 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 March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of March 31, 2012. Current losses deferred as regulatory assets include $115 million, $13 million, and $102 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of March 31, 2012. Current gains deferred as regulatory liabilities include $1 million and $1 million at Ameren and Ameren Illinois, respectively, as of December 31, 2011. Current losses deferred as regulatory assets include $101 million, $11 million, and $90 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of December 31, 2011.
Derivative Financial Instruments (Maximum Exposure If Counterparties Fail To Perform On Contracts) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2012
Dec. 31, 2011
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
$ 1,004 
$ 790 
Affiliates [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
267 1
276 1
Coal Producers [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
 
37 
Commodity Marketing Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
5 
89 
Electric Utilities [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
30 
16 
Financial Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
118 
84 
Municipalities/Cooperatives [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
465 
198 
Oil And Gas Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
8 
3 
Retail Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Maximum exposure to counterparties related to derivative contracts
$ 111 
$ 87 
Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 953 
$ 750 
Affiliates [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
267 1
274 1
Coal Producers [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
 
35 
Commodity Marketing Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
4 
88 
Electric Utilities [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
13 
9 
Financial Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
98 
65 
Municipalities/Cooperatives [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
459 
191 
Oil And Gas Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
2 
2 
Retail Companies [Member]
 
 
Concentration Risk [Line Items]
 
 
Potential loss on counterparty exposures related to derivative contracts
$ 110 
$ 86 
Derivative Financial Instruments (Cash Flow Hedges) (Details) (Power [Member], Operating Revenues-Electric [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Power [Member] |
Operating Revenues-Electric [Member]
 
 
Derivative [Line Items]
 
 
Amount of Gain (Loss) Recognized in OCI
$ 18 1 2
$ (4)1 2
Amount of (Gain) Loss Reclassified from OCI into Income
4 2 3
1 2 3
Amount of Gain (Loss) Recognized in Income on Derivatives
$ 2 2 4
$ (1)2 4
Derivative Financial Instruments (Other Derivatives) (Details) (Not Designated As Hedging Instrument [Member], USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Derivative [Line Items]
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
$ 1 1
$ 17 1
Coal [Member] |
Operating Expenses-Fuel [Member]
 
 
Derivative [Line Items]
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
(4)1
 
Fuel Oils [Member] |
Operating Expenses-Fuel [Member]
 
 
Derivative [Line Items]
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
5 1
19 1
Natural Gas (Generation) [Member] |
Operating Expenses-Fuel [Member]
 
 
Derivative [Line Items]
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
1 1
 
Power [Member] |
Operating Revenues-Electric [Member]
 
 
Derivative [Line Items]
 
 
Amount of Gain (Loss) Recognized in Income on Nondesignated Derivatives
$ (1)1
$ (2)1
Derivative Financial Instruments (Derivatives That Qualify For Regulatory Deferral) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Derivative [Line Items]
 
 
Net change in market value of derivatives that qualify for regulatory deferral
$ (175)1
$ 61 1
Fuel Oils [Member]
 
 
Derivative [Line Items]
 
 
Net change in market value of derivatives that qualify for regulatory deferral
5 1
29 1
Natural Gas [Member]
 
 
Derivative [Line Items]
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(18)1
31 1
Power [Member]
 
 
Derivative [Line Items]
 
 
Net change in market value of derivatives that qualify for regulatory deferral
(162)1
2 1
Uranium [Member]
 
 
Derivative [Line Items]
 
 
Net change in market value of derivatives that qualify for regulatory deferral
 
$ (1)1
Fair Value Measurements (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2012
Dec. 31, 2011
Fair Value Measurements [Abstract]
 
 
Gain (loss) recognized related to valuation adjustments for counterparty default risk
$ (2)
 
Valuation adjustments related to net derivative contracts
$ 8 
$ 1 
Fair Value Measurements (Schedule Of Valuation Process And Unobservable Inputs) (Details) (Commodity Contracts [Member], USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 3 Months Ended 3 Months Ended
Mar. 31, 2012
Fuel Oils [Member]
Dec. 31, 2011
Fuel Oils [Member]
Mar. 31, 2012
Power [Member]
Dec. 31, 2011
Power [Member]
Mar. 31, 2012
Uranium [Member]
Dec. 31, 2011
Uranium [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Option Model [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Option Model [Member]
Uranium [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Option Model [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Option Model [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Option Model [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Credit Risk Discount [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Credit Risk Discount [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Credit Risk Discount [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Power Forward/Swaps Third Party Pricing [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Power Forward/Swaps Third Party Pricing [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Power Forward/Swaps Third Party Pricing [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Basis To Nodal Valuation Price [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Basis To Nodal Valuation Price [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Basis To Nodal Valuation Price [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Power Market Simulation Model [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Power Market Simulation Model [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Power Market Simulation Model [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Contract Price Allocation [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Contract Price Allocation [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Contract Price Allocation [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Third Party Pricing [Member]
Minimum [Member]
Uranium [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Third Party Pricing [Member]
Maximum [Member]
Uranium [Member]
Mar. 31, 2012
Derivative Liabilities [Member]
Third Party Pricing [Member]
Weighted Average [Member]
Uranium [Member]
Mar. 31, 2012
Derivative Assets [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Escalated Exchange Settled Pricing [Member]
Minimum [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Escalated Exchange Settled Pricing [Member]
Maximum [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Escalated Exchange Settled Pricing [Member]
Weighted Average [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Option Model [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Option Model [Member]
Minimum [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Option Model [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Option Model [Member]
Maximum [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Option Model [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Option Model [Member]
Weighted Average [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Option Model [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Credit Risk Discount [Member]
Minimum [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Credit Risk Discount [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Credit Risk Discount [Member]
Maximum [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Credit Risk Discount [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Credit Risk Discount [Member]
Weighted Average [Member]
Fuel Oils [Member]
Mar. 31, 2012
Derivative Assets [Member]
Credit Risk Discount [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Power Forward/Swaps Third Party Pricing [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Power Forward/Swaps Third Party Pricing [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Power Forward/Swaps Third Party Pricing [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
FTR Third Party Pricing [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
FTR Third Party Pricing [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
FTR Third Party Pricing [Member]
Weighted Average [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Basis To Nodal Valuation Price [Member]
Minimum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Basis To Nodal Valuation Price [Member]
Maximum [Member]
Power [Member]
Mar. 31, 2012
Derivative Assets [Member]
Basis To Nodal Valuation Price [Member]
Weighted Average [Member]
Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets
$ 45 1 2
$ 37 1 2
$ 185 1 2
$ 195 1 2
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 170 1 2 3
 
 
 
$ 9 1 2
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivative liabilities
$ 1 1 2
$ 2 1 2
$ 210 1 2
$ 80 1 2
$ 1 1 2
$ 1 1 2
$ 194 1 2 3
$ 1 1 2 3
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Escalation rate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.68% 4
0.71% 4
0.71% 4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Volatilities
 
 
 
 
 
 
 
 
15.00% 5
40.00% 5
24.00% 5
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
23.00% 4
15.00% 5
28.00% 4
68.00% 5
25.00% 4
19.00% 5
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average bid/ask consensus pricing
 
 
 
 
 
 
 
 
$ 16 5
$ 39 5
$ 34 5
 
 
 
$ 20 5
$ 49 5
$ 28 5
 
 
 
 
 
 
 
 
 
$ 51 4
$ 55 4
$ 52 4
 
 
 
 
 
 
$ 16 5
 
$ 39 5
 
$ 35 5
 
 
 
 
 
 
$ 20 5
$ 49 5
$ 29 5
 
 
 
 
 
 
Counterparty credit risk
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.12% 
0.06% 
12.00% 
13.00% 
1.00% 
5.00% 
 
 
 
 
 
 
 
 
 
Estimated auction price
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ (1,569)4
$ 3,019 4
$ 173 4
 
 
 
Nodal basis
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ (6)4
$ (0.20)4
$ (3)4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ (6)4
$ (0.20)4
$ (3)4
Estimated future gas prices
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 4 4
$ 6 4
$ 5 4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated renewable energy credit costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 5 4
$ 7 4
$ 6 4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ameren credit risk
 
 
 
 
 
 
 
 
 
 
 
3.00% 5
6.00% 5
6.00% 5
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value Measurements (Schedule Of Fair Value Hierarchy Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Excluded receivables, payables, and accrued income, net
$ (1)
$ (1)
Cash and Cash Equivalents [Member]
 
 
Nuclear Decommissioning Trust Fund
3 1 2
3 1 2
Cash and Cash Equivalents [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Nuclear Decommissioning Trust Fund
3 1 2
3 1 2
Cash and Cash Equivalents [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Cash and Cash Equivalents [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Commodity Contracts [Member] |
Coal [Member]
 
 
Derivative liabilities
4 1 3
 
Commodity Contracts [Member] |
Coal [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Derivative liabilities
4 1 3
 
Commodity Contracts [Member] |
Fuel Oils [Member]
 
 
Derivative assets
45 1 3
37 1 3
Derivative liabilities
1 1 3
2 1 3
Commodity Contracts [Member] |
Fuel Oils [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Derivative assets
36 1 3
33 1 3
Derivative liabilities
1 1 3
2 1 3
Commodity Contracts [Member] |
Fuel Oils [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Derivative assets
 
   1 3
Derivative liabilities
 
   1 3
Commodity Contracts [Member] |
Fuel Oils [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Derivative assets
9 1 3
4 1 3
Derivative liabilities
 
   1 3
Commodity Contracts [Member] |
Natural Gas [Member]
 
 
Derivative assets
6 1 3
6 1 3
Derivative liabilities
215 1 3
198 1 3
Commodity Contracts [Member] |
Natural Gas [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Derivative assets
4 1 3
4 1 3
Derivative liabilities
19 1 3
22 1 3
Commodity Contracts [Member] |
Natural Gas [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Derivative assets
2 1 3
   1 3
Derivative liabilities
196 1 3
   1 3
Commodity Contracts [Member] |
Natural Gas [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Derivative assets
 
2 1 3
Derivative liabilities
 
176 1 3
Commodity Contracts [Member] |
Power [Member]
 
 
Derivative assets
185 1 3
195 1 3
Derivative liabilities
210 1 3
80 1 3
Commodity Contracts [Member] |
Power [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Derivative assets
 
   1 3
Derivative liabilities
 
   1 3
Commodity Contracts [Member] |
Power [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Derivative assets
15 1 3
2 1 3
Derivative liabilities
16 1 3
2 1 3
Commodity Contracts [Member] |
Power [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Derivative assets
170 1 3
193 1 3
Derivative liabilities
194 1 3
78 1 3
Commodity Contracts [Member] |
Uranium [Member]
 
 
Derivative liabilities
1 1 3
1 1 3
Commodity Contracts [Member] |
Uranium [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Derivative liabilities
 
   1 3
Commodity Contracts [Member] |
Uranium [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Derivative liabilities
 
   1 3
Commodity Contracts [Member] |
Uranium [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Derivative liabilities
1 1 3
1 1 3
Equity Securities [Member] |
U.S. Large Capitalization [Member]
 
 
Nuclear Decommissioning Trust Fund
264 1 2
234 1 2
Equity Securities [Member] |
U.S. Large Capitalization [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Nuclear Decommissioning Trust Fund
264 1 2
234 1 2
Equity Securities [Member] |
U.S. Large Capitalization [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Equity Securities [Member] |
U.S. Large Capitalization [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Corporate Debt Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
46 1 2
44 1 2
Debt Securities [Member] |
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Nuclear Decommissioning Trust Fund
46 1 2
44 1 2
Debt Securities [Member] |
Corporate Debt Securities [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Municipal Bonds [Member]
 
 
Nuclear Decommissioning Trust Fund
1 1 2
1 1 2
Debt Securities [Member] |
Municipal Bonds [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Municipal Bonds [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Nuclear Decommissioning Trust Fund
1 1 2
1 1 2
Debt Securities [Member] |
Municipal Bonds [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
U.S. Treasury And Agency Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
66 1 2
65 1 2
Debt Securities [Member] |
U.S. Treasury And Agency Securities [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
U.S. Treasury And Agency Securities [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Nuclear Decommissioning Trust Fund
66 1 2
65 1 2
Debt Securities [Member] |
U.S. Treasury And Agency Securities [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Asset-backed Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
10 1 2
10 1 2
Debt Securities [Member] |
Asset-backed Securities [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Asset-backed Securities [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Nuclear Decommissioning Trust Fund
10 1 2
10 1 2
Debt Securities [Member] |
Asset-backed Securities [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Other Debt Securities [Member]
 
 
Nuclear Decommissioning Trust Fund
1 1 2
1 1 2
Debt Securities [Member] |
Other Debt Securities [Member] |
Fair Value, Inputs, Level 1 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Debt Securities [Member] |
Other Debt Securities [Member] |
Fair Value, Inputs, Level 2 [Member]
 
 
Nuclear Decommissioning Trust Fund
1 1 2
1 1 2
Debt Securities [Member] |
Other Debt Securities [Member] |
Fair Value, Inputs, Level 3 [Member]
 
 
Nuclear Decommissioning Trust Fund
 
   1 2
Fair Value Measurements (Schedule Of Changes In The Fair Value Of Financial Assets And Liabilities Classified As Level 3 In The Fair Value Hierarchy) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Fuel Oils [Member]
Mar. 31, 2011
Fuel Oils [Member]
Mar. 31, 2012
Natural Gas [Member]
Mar. 31, 2011
Natural Gas [Member]
Mar. 31, 2012
Power [Member]
Mar. 31, 2011
Power [Member]
Mar. 31, 2011
Uranium [Member]
Mar. 31, 2012
Uranium [Member]
Dec. 31, 2011
Uranium [Member]
Beginning balance
$ 4 
$ 51 
$ (174)
$ (148)
$ 115 
$ 36 
$ 2 
$ (1)
$ (1)
Included in earnings
2 1
22 1
 
 
8 1
(3)1
 
 
 
Included in OCI
 
 
 
 
24 
 
 
 
 
Included in regulatory assets/liabilities
2 
31 
(28)
7 
(158)
(2)
(1)
 
 
Total realized and unrealized gains (losses)
4 
53 
(28)
7 
(126)
(5)
(1)
 
 
Purchases
 
1 
 
 
(1)
9 
 
 
 
Sales
 
 
 
 
1 
(9)
 
 
 
Settlements
 
(9)
17 
21 
(14)
 
 
 
 
Transfers into Level 3
2 
 
 
 
 
 
 
 
 
Transfers out of Level 3
(1)
 
185 
 
1 
 
 
 
 
Ending balance
9 
96 
 
(120)
(24)
31 
1 
(1)
(1)
Change in unrealized gains (losses) related to assets/liabilities still held
$ 3 
$ 69 
 
$ 7 
$ (133)
$ 9 
$ (1)
 
 
Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
Net fair value of Level 3 transfers
$ 187 1
Fuel Oils [Member]
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
Transfers into Level 3 / Transfers out of Level 1
2 1
Transfers out of Level 3 / Transfers into Level 1
(1)1
Natural Gas [Member]
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
Transfers out of Level 3 / Transfers into Level 2
185 1
Power [Member]
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
Transfers out of Level 3 / Transfers into Level 2
$ 1 1
Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Dec. 31, 2011
Noncontrolling interest
20.00% 
 
Carrying Amount [Member]
 
 
Long-term debt and capital lease obligations (including current portion)
$ 6,856 1 2
$ 6,856 1 2
Preferred stock
142 1 2
142 1 2
Fair Value [Member]
 
 
Long-term debt and capital lease obligations (including current portion)
7,673 1 2
7,800 1 2
Preferred stock
$ 93 1 2
$ 92 1 2
Commitments And Contingencies (Callaway Energy Center) (Details) (USD $)
3 Months Ended 3 Months Ended
Mar. 31, 2012
W
Jun. 30, 2012
Ameren Illinois Company [Member]
MW
Mar. 31, 2012
Public Liability And Nuclear Worker Liability - American Nuclear Insurers [Member]
Mar. 31, 2012
Public Liability And Nuclear Worker Liability - Pool Participation [Member]
Mar. 31, 2012
Property Damage - Nuclear Electric Insurance Ltd [Member]
Mar. 31, 2012
Replacement Power - Nuclear Electric Insurance Ltd [Member]
Mar. 31, 2012
Replacement Power - Energy Risk Assurance Company [Member]
Insurance aggregate maximum coverage
$ 12,594,000,000 1
 
$ 375,000,000 
$ 12,219,000,000 2
$ 2,750,000,000 3
$ 490,000,000 4
$ 64,000,000 5
Insurance maximum coverage per incident
118,000,000 
 
 
118,000,000 6
23,000,000 
9,000,000 
 
Threshold for which a retrospective assessment for a covered loss is necessary
375,000,000 
 
 
 
 
 
 
Annual payment in the event of an incident at any licensed commercial reactor
17,500,000 
 
 
 
 
 
 
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act
118,000,000 
 
 
 
 
 
 
Maximum annual payment to be paid in a calendar year per reactor incident under liability provisions of Atomic Energy Act
17,500,000 
 
 
 
 
 
 
Amount of primary property liability coverage
500,000,000 
 
 
 
 
 
 
Amount of coverage in excess of primary property liability coverage
2,250,000,000 
 
 
 
 
 
 
Losses in excess of primary coverage
500,000,000 
 
 
 
 
 
 
Amount of weekly indemnity coverage commencing eight weeks after power outage
4,500,000 
 
 
 
 
 
 
Number of weeks of coverage after the first eight weeks of an outage
52 
 
 
 
 
 
 
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage
3,600,000 
 
 
 
 
 
 
Number of additional weeks after initial indemnity coverage for power outage, minimum
71 
 
 
 
 
 
 
Amount of weekly indemnity coverage thereafter not exceeding policy limit
 
 
 
 
 
490,000,000 
3,600,000 
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 
 
 
 
 
 
 
Purchase commitment, MW's
 
48,000 
 
 
 
 
 
Purchase commitment
 
$ 15,000,000 
 
 
 
 
 
Commitments And Contingencies (Environmental Matters) (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended 3 Months Ended
Dec. 21, 2011
Mar. 31, 2012
Number of states participating in the cap-and-trade program
 
28 
Percent of top performing facilities
12.00% 
 
Estimated Capital Costs 2012 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
 
$ 210 
Manufactured Gas Plant [Member]
 
 
Loss contingency range of possible loss minimum
 
102.0 
Loss contingency range of possible loss maximum
 
174 
Accrual for environmental loss contingencies
 
102.0 1
Manufactured Gas Plant [Member] |
Ameren Illinois Company [Member]
 
 
Number of remediation sites
 
44 
Manufactured Gas Plant [Member] |
Ameren Missouri [Member]
 
 
Number of remediation sites
 
10 
Former Coal Ash Landfill [Member] |
Ameren Illinois Company [Member]
 
 
Loss contingency range of possible loss minimum
 
0.5 
Loss contingency range of possible loss maximum
 
6 
Accrual for environmental loss contingencies
 
0.5 
Other Environmental [Member] |
Ameren Illinois Company [Member]
 
 
Accrual for environmental loss contingencies
 
0.8 
Former Coal Tar Distillery [Member] |
Ameren Missouri [Member]
 
 
Loss contingency range of possible loss minimum
 
2.0 
Loss contingency range of possible loss maximum
 
5 
Accrual for environmental loss contingencies
 
2.0 
Sauget Area 2 [Member] |
Ameren Missouri [Member]
 
 
Loss contingency range of possible loss minimum
 
0.3 
Loss contingency range of possible loss maximum
 
10 
Accrual for environmental loss contingencies
 
0.3 
Minimum [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
 
1,825 
Minimum [Member] |
Estimated Capital Costs 2013 - 2016 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
 
445 
Minimum [Member] |
Estimated Capital Costs 2017 - 2021 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
 
1,170 
Maximum [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
 
2,185 
Maximum [Member] |
Estimated Capital Costs 2013 - 2016 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
 
550 
Maximum [Member] |
Estimated Capital Costs 2017 - 2021 [Member]
 
 
Estimated capital costs to comply with existing and known federal and state air emissions regulations
 
$ 1,425 
Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Commitments And Contingencies [Abstract]
 
Insurance settlements receivable
$ 68 
Callaway Nuclear Plant (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Mar. 31, 2012
Dec. 31, 2011
Dec. 31, 2010
Dec. 31, 2009
Callaway Nuclear Plant [Abstract]
 
 
 
 
Number of mills charged for NWF fee
1 
 
 
 
Assumed life of plant, in years
40 
 
 
 
Annual decommissioning costs included in costs of service
 
$ 7 
$ 7 
$ 7 
Asset Impairments (Narrative) (Details) (USD $)
2 Months Ended 3 Months Ended
Feb. 29, 2012
Mar. 31, 2012
Mar. 31, 2011
Dec. 31, 2011
Percentage decrease in market price
14.00% 
 
 
 
Noncash impairment charge
 
$ 628,000,000 
    
 
Property, plant and equipment, net
 
17,535,000,000 
 
18,127,000,000 
Merchant Generation [Member]
 
 
 
 
Property, plant and equipment, net
 
2,600,000,000 
 
 
Long-Lived asset carrying value in excess of estimated fair value
 
$ 1,000,000,000 
 
 
Retirement Benefits (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2012
Defined benefit plan, estimated future employer contributions during the next five years
$ 580 
Minimum [Member]
 
Defined benefit plan, estimated future employer contributions during the next five years
90 
Maximum [Member]
 
Defined benefit plan, estimated future employer contributions during the next five years
$ 150 
Retirement Benefits (Components Of Net Periodic Benefit Cost) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Pension Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Service cost
$ 21 
$ 20 
Interest cost
43 
45 
Expected return on plan assets
(54)
(54)
Amortization of prior service cost (benefit)
   
   
Amortization of actuarial loss
20 
11 
Net periodic benefit cost
30 
22 
Postretirement Benefits [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Service cost
6 
6 
Interest cost
14 
15 
Expected return on plan assets
(14)
(14)
Amortization of prior service cost (benefit)
(1)
(2)
Amortization of actuarial loss
4 
1 
Net periodic benefit cost
$ 9 
$ 6 
Retirement Benefits (Summary Of Benefit Plan Costs Incurred) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Pension Benefits [Member]
 
 
Net periodic benefit cost
$ 30 
$ 22 
Postretirement Benefits [Member]
 
 
Net periodic benefit cost
$ 9 
$ 6 
Segment Information (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2012
Mar. 31, 2011
Dec. 31, 2011
Segment Reporting Information [Line Items]
 
 
 
External revenues
$ 1,658 
$ 1,904 
 
Net Income(Loss)
(403)1
71 1
 
Total assets
22,899 
 
23,645 
Ameren Missouri [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
External revenues
686 
767 
 
Intersegment revenues
5 
5 
 
Net Income(Loss)
21 1
21 1
 
Total assets
12,546 
 
12,757 
Ameren Illinois Company [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
External revenues
721 
805 
 
Intersegment revenues
3 
3 
 
Net Income(Loss)
27 1
33 1
 
Total assets
7,256 
 
7,213 
Merchant Generation [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
External revenues
249 
332 
 
Intersegment revenues
87 
47 
 
Net Income(Loss)
(363)1
20 1
 
Total assets
3,266 
 
3,833 
Other Segment [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
External revenues
1 
 
 
Intersegment revenues
1 
1 
 
Net Income(Loss)
(88)1
(3)1
 
Total assets
1,261 
 
1,211 
Intersegment Elimination [Member]
 
 
 
Segment Reporting Information [Line Items]
 
 
 
External revenues
1 
 
 
Intersegment revenues
(96)
(56)
 
Total assets
$ (1,430)
 
$ (1,369)