ý | Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended June 30, 2013 |
¨ | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to |
Commission File Number | Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number | IRS Employer Identification No. | ||
1-14756 | Ameren Corporation | 43-1723446 | ||
(Missouri Corporation) | ||||
1901 Chouteau Avenue | ||||
St. Louis, Missouri 63103 | ||||
(314) 621-3222 | ||||
1-2967 | Union Electric Company | 43-0559760 | ||
(Missouri Corporation) | ||||
1901 Chouteau Avenue | ||||
St. Louis, Missouri 63103 | ||||
(314) 621-3222 | ||||
1-3672 | Ameren Illinois Company | 37-0211380 | ||
(Illinois Corporation) | ||||
6 Executive Drive | ||||
Collinsville, Illinois 62234 | ||||
(618) 343-8150 |
Ameren Corporation | Yes | ý | No | ¨ | ||||
Union Electric Company | Yes | ý | No | ¨ | ||||
Ameren Illinois Company | Yes | ý | No | ¨ |
Ameren Corporation | Yes | ý | No | ¨ | ||||
Union Electric Company | Yes | ý | No | ¨ | ||||
Ameren Illinois Company | Yes | ý | No | ¨ |
Large Accelerated Filer | Accelerated Filer | Non-Accelerated Filer | Smaller Reporting Company | |||||
Ameren Corporation | ý | ¨ | ¨ | ¨ | ||||
Union Electric Company | ¨ | ¨ | ý | ¨ | ||||
Ameren Illinois Company | ¨ | ¨ | ý | ¨ |
Ameren Corporation | Yes | ¨ | No | ý | ||||
Union Electric Company | Yes | ¨ | No | ý | ||||
Ameren Illinois Company | Yes | ¨ | No | ý |
Ameren Corporation | Common stock, $0.01 par value per share - 242,634,671 | |
Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant) - 102,123,834 | |
Ameren Illinois Company | Common stock, no par value, held by Ameren Corporation (parent company of the registrant) - 25,452,373 |
Page | ||
Item 1. | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 1. | ||
Item 1A. | ||
Item 2. | ||
Item 6. | ||
• | completion of our divestiture of New AER and the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers; |
• | regulatory approvals, including from FERC, the FCC, and the Illinois Pollution Control Board relating to, and the satisfaction or waiver of the conditions to, the divestiture of New AER and regulatory approvals from FERC with respect to both the transfer to Medina Valley and ultimate sale to a third-party of the Elgin, Gibson City, and Grand Tower gas-fired energy centers; |
• | Ameren's exit from the Merchant Generation business, which could result in additional impairments of long-lived assets, disposal-related losses, contingencies, reduction of existing deferred tax assets, or could have other adverse impacts on the financial condition, results of operations and liquidity of Ameren; |
• | regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of Ameren Illinois' natural gas delivery service rate case filed in 2013; the court appeals of Ameren Missouri's and Ameren Illinois' electric rate orders issued in 2012; Ameren Missouri’s current FAC prudence review by the MoPSC; Ameren Missouri's request with the MoPSC for an accounting authority order relating to the deferral of certain fixed costs; Ameren Illinois' request for rehearing of FERC’s July 2012 and June 2013 orders regarding the alleged inclusion of acquisition premiums in Ameren Illinois transmission rates; and future regulatory, judicial, or legislative actions that seek to change regulatory recovery mechanisms; |
• | the effect of Ameren Illinois participating in a performance-based formula ratemaking process under the IEIMA, including the direct relationship between Ameren Illinois’ return on common equity and the 30-year United States Treasury bond yields, the related financial commitments required by the IEIMA, and the resulting uncertain impact on the financial condition, results of operations and liquidity of Ameren Illinois; |
• | Ameren Illinois’ decision of when to participate in the regulatory framework provided by the state of Illinois’ recently enacted Natural Gas Consumer, Safety and Reliability Act, which allows for the use of a rider to recover costs of certain infrastructure investments made between rate cases; |
• | the effects of, or changes to, the Illinois power procurement process; |
• | the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our |
• | changes in laws and other governmental actions, including monetary, fiscal, and tax policies, such as changes that result in our being unable to claim all or a portion of the cash tax benefits that are expected to result from the divestiture of AER; |
• | the effects on demand for our services resulting from technological advances, including advances in energy efficiency and distributed generation sources, which generate electricity at the site of consumption; |
• | increasing capital expenditure and operating expense requirements and our ability to recover these costs; |
• | the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities; |
• | the effectiveness of our risk management strategies and the use of financial and derivative instruments; |
• | the level and volatility of future prices for power in the Midwest, which may have a significant effect on the financial condition of Ameren's Merchant Generation segment; |
• | business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products; |
• | disruptions of the capital markets, deterioration in credit metrics of the Ameren Companies, or other events that make the Ameren Companies' access to necessary capital, including short-term credit and liquidity, impossible, more difficult, or more costly; |
• | our assessment of our liquidity, including liquidity concerns for Ameren's Merchant Generation business, and specifically for Genco, whose ability to borrow additional funds from external, third-party sources is restricted; |
• | the impact of the adoption of new accounting guidance and the application of appropriate technical accounting rules and guidance; |
• | actions of credit rating agencies and the effects of such actions; |
• | the impact of weather conditions and other natural phenomena on us and our customers, including the impacts of droughts, which may cause lower river levels and could limit our energy centers' ability to generate power; |
• | the impact of system outages; |
• | generation, transmission, and distribution asset construction, installation, performance, and cost recovery; |
• | the effects of our increasing investment in electric transmission projects and uncertainty as to whether we will achieve our expected investment and returns in a timely fashion, if at all; |
• | the extent to which Ameren Missouri prevails in its claims against insurers in connection with its Taum Sauk pumped-storage hydroelectric energy center incident; |
• | the extent to which Ameren Missouri is permitted by its regulators to recover in rates the investments it made in connection with additional nuclear generation at its Callaway energy center; |
• | operation of Ameren Missouri's Callaway energy center, including planned, unplanned and refueling outages, and future decommissioning costs; |
• | the effects of strategic initiatives, including mergers, acquisitions and divestitures, including the divestiture of the Merchant Generation business, and any related tax implications; |
• | the impact of current environmental regulations on utilities and power generating companies and new, more stringent or changing requirements, including those related to greenhouse gases, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of our energy centers, increase our costs, result in an impairment of our assets, result in sales of our assets, reduce our customers' demand for electricity or natural gas, or otherwise have a negative financial effect; |
• | the impact of complying with renewable energy portfolio requirements in Missouri; |
• | labor disputes, workforce reductions, future wage and employee benefits costs, including changes in discount rates and returns on benefit plan assets; |
• | the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit agreements, and financial instruments; |
• | the cost and availability of transmission capacity for the energy generated by Ameren's and Ameren Missouri's energy centers or required to satisfy energy sales made by Ameren or Ameren Missouri; |
• | legal and administrative proceedings; and |
• | acts of sabotage, war, terrorism, cybersecurity attacks or intentionally disruptive acts. |
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Operating Revenues: | |||||||||||||||
Electric | $ | 1,228 | $ | 1,255 | $ | 2,316 | $ | 2,319 | |||||||
Gas | 175 | 147 | 562 | 495 | |||||||||||
Total operating revenues | 1,403 | 1,402 | 2,878 | 2,814 | |||||||||||
Operating Expenses: | |||||||||||||||
Fuel | 213 | 175 | 426 | 356 | |||||||||||
Purchased power | 121 | 161 | 272 | 370 | |||||||||||
Gas purchased for resale | 72 | 49 | 302 | 264 | |||||||||||
Other operations and maintenance | 447 | 395 | 846 | 764 | |||||||||||
Depreciation and amortization | 178 | 168 | 353 | 335 | |||||||||||
Taxes other than income taxes | 111 | 110 | 233 | 223 | |||||||||||
Total operating expenses | 1,142 | 1,058 | 2,432 | 2,312 | |||||||||||
Operating Income | 261 | 344 | 446 | 502 | |||||||||||
Other Income and Expenses: | |||||||||||||||
Miscellaneous income | 16 | 19 | 31 | 36 | |||||||||||
Miscellaneous expense | 5 | 7 | 13 | 22 | |||||||||||
Total other income | 11 | 12 | 18 | 14 | |||||||||||
Interest Charges | 100 | 98 | 201 | 196 | |||||||||||
Income Before Income Taxes | 172 | 258 | 263 | 320 | |||||||||||
Income Taxes | 66 | 96 | 101 | 119 | |||||||||||
Income from Continuing Operations | 106 | 162 | 162 | 201 | |||||||||||
Income (Loss) from Discontinued Operations, Net of Taxes (Note 2) | (10 | ) | 48 | (209 | ) | (394 | ) | ||||||||
Net Income (Loss) | 96 | 210 | (47 | ) | (193 | ) | |||||||||
Less: Net Income (Loss) Attributable to Noncontrolling Interests: | |||||||||||||||
Continuing Operations | 1 | 1 | 3 | 3 | |||||||||||
Discontinued Operations | — | (2 | ) | — | (4 | ) | |||||||||
Net Income (Loss) Attributable to Ameren Corporation: | |||||||||||||||
Continuing Operations | 105 | 161 | $ | 159 | $ | 198 | |||||||||
Discontinued Operations | (10 | ) | 50 | (209 | ) | (390 | ) | ||||||||
Net Income (Loss) Attributable to Ameren Corporation | $ | 95 | $ | 211 | $ | (50 | ) | $ | (192 | ) | |||||
Earnings (Loss) per Common Share – Basic and Diluted: | |||||||||||||||
Continuing Operations | $ | 0.44 | $ | 0.66 | $ | 0.66 | $ | 0.81 | |||||||
Discontinued Operations | (0.05 | ) | 0.21 | (0.87 | ) | (1.60 | ) | ||||||||
Net Income (Loss) per Common Share – Basic and Diluted | $ | 0.39 | $ | 0.87 | $ | (0.21 | ) | $ | (0.79 | ) | |||||
Dividends per Common Share | $ | 0.40 | $ | 0.40 | $ | 0.80 | $ | 0.80 | |||||||
Average Common Shares Outstanding | 242.6 | 242.6 | 242.6 | 242.6 |
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Income from Continuing Operations | $ | 106 | $ | 162 | $ | 162 | $ | 201 | |||||||
Other Comprehensive Income, Net of Taxes | |||||||||||||||
Pension and other postretirement benefit plan activity, net of income taxes of $8, $-, $8, and $-, respectively | 10 | 1 | 10 | 1 | |||||||||||
Total other comprehensive income, net of taxes | 10 | 1 | 10 | 1 | |||||||||||
Comprehensive Income from Continuing Operations | 116 | 163 | 172 | 202 | |||||||||||
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 1 | 1 | 3 | 3 | |||||||||||
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation | 115 | 162 | 169 | 199 | |||||||||||
Net Income (Loss) from Discontinued Operations | (10 | ) | 48 | (209 | ) | (394 | ) | ||||||||
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Taxes | (4 | ) | 4 | (11 | ) | 19 | |||||||||
Comprehensive Income (Loss) from Discontinued Operations | (14 | ) | 52 | (220 | ) | (375 | ) | ||||||||
Less: Comprehensive Loss from Discontinued Operations Attributable to Noncontrolling Interest | — | (2 | ) | — | (4 | ) | |||||||||
Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation | (14 | ) | 54 | (220 | ) | (371 | ) | ||||||||
Comprehensive Income (Loss) Attributable to Ameren Corporation | $ | 101 | $ | 216 | $ | (51 | ) | $ | (172 | ) |
June 30, 2013 | December 31, 2012 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 150 | $ | 184 | |||
Accounts receivable – trade (less allowance for doubtful accounts of $22 and $17, respectively) | 425 | 354 | |||||
Unbilled revenue | 308 | 291 | |||||
Miscellaneous accounts and notes receivable | 75 | 71 | |||||
Materials and supplies | 511 | 570 | |||||
Current regulatory assets | 192 | 247 | |||||
Current accumulated deferred income taxes, net | 157 | 160 | |||||
Other current assets | 104 | 98 | |||||
Current assets of discontinued operations | 1,486 | 1,600 | |||||
Total current assets | 3,408 | 3,575 | |||||
Property and Plant, Net | 15,601 | 15,348 | |||||
Investments and Other Assets: | |||||||
Nuclear decommissioning trust fund | 442 | 408 | |||||
Goodwill | 411 | 411 | |||||
Intangible assets | 18 | 14 | |||||
Regulatory assets | 1,742 | 1,786 | |||||
Other assets | 654 | 667 | |||||
Total investments and other assets | 3,267 | 3,286 | |||||
TOTAL ASSETS | $ | 22,276 | $ | 22,209 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities: | |||||||
Current maturities of long-term debt | $ | 884 | $ | 355 | |||
Short-term debt | 25 | — | |||||
Accounts and wages payable | 428 | 533 | |||||
Taxes accrued | 123 | 50 | |||||
Interest accrued | 100 | 89 | |||||
Customer deposits | 110 | 107 | |||||
Mark-to-market derivative liabilities | 75 | 92 | |||||
Current regulatory liabilities | 180 | 100 | |||||
Other current liabilities | 178 | 168 | |||||
Current liabilities of discontinued operations | 1,183 | 1,166 | |||||
Total current liabilities | 3,286 | 2,660 | |||||
Long-term Debt, Net | 5,274 | 5,802 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes, net | 3,348 | 3,166 | |||||
Accumulated deferred investment tax credits | 67 | 70 | |||||
Regulatory liabilities | 1,666 | 1,589 | |||||
Asset retirement obligations | 385 | 375 | |||||
Pension and other postretirement benefits | 1,140 | 1,138 | |||||
Other deferred credits and liabilities | 585 | 642 | |||||
Total deferred credits and other liabilities | 7,191 | 6,980 | |||||
Commitments and Contingencies (Notes 2, 3, 9, 10 and 11) | |||||||
Ameren Corporation Stockholders’ Equity: | |||||||
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 242.6 | 2 | 2 | |||||
Other paid-in capital, principally premium on common stock | 5,619 | 5,616 | |||||
Retained earnings | 762 | 1,006 | |||||
Accumulated other comprehensive loss | (9 | ) | (8 | ) | |||
Total Ameren Corporation stockholders’ equity | 6,374 | 6,616 | |||||
Noncontrolling Interests | 151 | 151 | |||||
Total equity | 6,525 | 6,767 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 22,276 | $ | 22,209 |
AMEREN CORPORATION | |||||||
CONSOLIDATED STATEMENT OF CASH FLOWS | |||||||
(Unaudited) (In millions) | |||||||
Six months ended June 30, | |||||||
2013 | 2012 | ||||||
Cash Flows From Operating Activities: | |||||||
Net loss | $ | (47 | ) | $ | (193 | ) | |
Loss from discontinued operations, net of taxes | 209 | 394 | |||||
Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||
Depreciation and amortization | 334 | 314 | |||||
Amortization of nuclear fuel | 29 | 41 | |||||
Amortization of debt issuance costs and premium/discounts | 12 | 8 | |||||
Deferred income taxes and investment tax credits, net | 70 | 110 | |||||
Allowance for equity funds used during construction | (16 | ) | (17 | ) | |||
Stock-based compensation costs | 14 | 12 | |||||
Other | 18 | (6 | ) | ||||
Changes in assets and liabilities: | |||||||
Receivables | (92 | ) | (16 | ) | |||
Materials and supplies | 77 | 19 | |||||
Accounts and wages payable | (75 | ) | (138 | ) | |||
Taxes accrued | 67 | 66 | |||||
Assets, other | 49 | 12 | |||||
Liabilities, other | 9 | 36 | |||||
Pension and other postretirement benefits | 36 | 23 | |||||
Counterparty collateral, net | 35 | (1 | ) | ||||
Net cash provided by operating activities - continuing operations | 729 | 664 | |||||
Net cash provided by operating activities - discontinued operations | 39 | 97 | |||||
Net cash provided by operating activities | 768 | 761 | |||||
Cash Flows From Investing Activities: | |||||||
Capital expenditures | (575 | ) | (485 | ) | |||
Nuclear fuel expenditures | (25 | ) | (52 | ) | |||
Purchases of securities – nuclear decommissioning trust fund | (97 | ) | (206 | ) | |||
Sales and maturities of securities – nuclear decommissioning trust fund | 89 | 195 | |||||
Other | 2 | (1 | ) | ||||
Net cash used in investing activities - continuing operations | (606 | ) | (549 | ) | |||
Net cash used in investing activities - discontinued operations | (31 | ) | (64 | ) | |||
Net cash used in investing activities | (637 | ) | (613 | ) | |||
Cash Flows From Financing Activities: | |||||||
Dividends on common stock | (194 | ) | (187 | ) | |||
Dividends paid to noncontrolling interest holders | (3 | ) | (3 | ) | |||
Short-term debt, net | 25 | (118 | ) | ||||
Advances received for construction | 7 | 3 | |||||
Net cash used in financing activities - continuing operations | (165 | ) | (305 | ) | |||
Net cash used in financing activities - discontinued operations | — | — | |||||
Net cash used in financing activities | (165 | ) | (305 | ) | |||
Net change in cash and cash equivalents | (34 | ) | (157 | ) | |||
Cash and cash equivalents at beginning of year | 184 | 248 | |||||
Cash and cash equivalents at end of period | $ | 150 | $ | 91 | |||
Noncash financing activity – dividends on common stock | $ | — | $ | (7 | ) |
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Operating Revenues: | |||||||||||||||
Electric | $ | 860 | $ | 822 | $ | 1,592 | $ | 1,458 | |||||||
Gas | 29 | 21 | 93 | 76 | |||||||||||
Other | — | 1 | — | 1 | |||||||||||
Total operating revenues | 889 | 844 | 1,685 | 1,535 | |||||||||||
Operating Expenses: | |||||||||||||||
Fuel | 213 | 177 | 426 | 357 | |||||||||||
Purchased power | 41 | — | 67 | 20 | |||||||||||
Gas purchased for resale | 11 | 5 | 48 | 37 | |||||||||||
Other operations and maintenance | 253 | 206 | 474 | 408 | |||||||||||
Depreciation and amortization | 113 | 109 | 224 | 217 | |||||||||||
Taxes other than income taxes | 79 | 78 | 156 | 149 | |||||||||||
Total operating expenses | 710 | 575 | 1,395 | 1,188 | |||||||||||
Operating Income | 179 | 269 | 290 | 347 | |||||||||||
Other Income and Expenses: | |||||||||||||||
Miscellaneous income | 14 | 18 | 28 | 33 | |||||||||||
Miscellaneous expense | 3 | 4 | 8 | 7 | |||||||||||
Total other income | 11 | 14 | 20 | 26 | |||||||||||
Interest Charges | 56 | 56 | 116 | 112 | |||||||||||
Income Before Income Taxes | 134 | 227 | 194 | 261 | |||||||||||
Income Taxes | 49 | 83 | 68 | 95 | |||||||||||
Net Income | 85 | 144 | 126 | 166 | |||||||||||
Other Comprehensive Income | — | — | — | — | |||||||||||
Comprehensive Income | $ | 85 | $ | 144 | $ | 126 | $ | 166 | |||||||
Net Income | $ | 85 | $ | 144 | $ | 126 | $ | 166 | |||||||
Preferred Stock Dividends | 1 | 1 | 2 | 2 | |||||||||||
Net Income Available to Common Stockholder | $ | 84 | $ | 143 | $ | 124 | $ | 164 |
June 30, 2013 | December 31, 2012 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 19 | $ | 148 | |||
Advances to money pool | — | 24 | |||||
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $5, respectively) | 229 | 161 | |||||
Accounts receivable – affiliates | 3 | 4 | |||||
Unbilled revenue | 225 | 145 | |||||
Miscellaneous accounts and notes receivable | 56 | 48 | |||||
Materials and supplies | 369 | 397 | |||||
Current regulatory assets | 132 | 163 | |||||
Other current assets | 100 | 69 | |||||
Total current assets | 1,133 | 1,159 | |||||
Property and Plant, Net | 10,264 | 10,161 | |||||
Investments and Other Assets: | |||||||
Nuclear decommissioning trust fund | 442 | 408 | |||||
Intangible assets | 18 | 14 | |||||
Regulatory assets | 830 | 852 | |||||
Other assets | 444 | 449 | |||||
Total investments and other assets | 1,734 | 1,723 | |||||
TOTAL ASSETS | $ | 13,131 | $ | 13,043 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current Liabilities: | |||||||
Current maturities of long-term debt | $ | 309 | $ | 205 | |||
Accounts and wages payable | 198 | 345 | |||||
Accounts payable – affiliates | 103 | 66 | |||||
Taxes accrued | 107 | 28 | |||||
Interest accrued | 73 | 60 | |||||
Current regulatory liabilities | 71 | 18 | |||||
Other current liabilities | 90 | 77 | |||||
Total current liabilities | 951 | 799 | |||||
Long-term Debt, Net | 3,697 | 3,801 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes, net | 2,474 | 2,443 | |||||
Accumulated deferred investment tax credits | 62 | 64 | |||||
Regulatory liabilities | 979 | 917 | |||||
Asset retirement obligations | 355 | 346 | |||||
Pension and other postretirement benefits | 465 | 461 | |||||
Other deferred credits and liabilities | 150 | 158 | |||||
Total deferred credits and other liabilities | 4,485 | 4,389 | |||||
Commitments and Contingencies (Notes 3, 9, 10 and 11) | |||||||
Stockholders’ Equity: | |||||||
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | 511 | |||||
Other paid-in capital, principally premium on common stock | 1,556 | 1,556 | |||||
Preferred stock not subject to mandatory redemption | 80 | 80 | |||||
Retained earnings | 1,851 | 1,907 | |||||
Total stockholders’ equity | 3,998 | 4,054 | |||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 13,131 | $ | 13,043 |
Six months ended June 30, | |||||||
2013 | 2012 | ||||||
Cash Flows From Operating Activities: | |||||||
Net income | $ | 126 | $ | 166 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | 208 | 201 | |||||
Amortization of nuclear fuel | 29 | 41 | |||||
FAC prudence review charge | 23 | — | |||||
Amortization of debt issuance costs and premium/discounts | 4 | 3 | |||||
Deferred income taxes and investment tax credits, net | 13 | 76 | |||||
Allowance for equity funds used during construction | (14 | ) | (15 | ) | |||
Changes in assets and liabilities: | |||||||
Receivables | (155 | ) | (65 | ) | |||
Materials and supplies | 28 | (43 | ) | ||||
Accounts and wages payable | (119 | ) | (164 | ) | |||
Taxes accrued | 79 | 29 | |||||
Assets, other | 61 | 12 | |||||
Liabilities, other | 37 | 42 | |||||
Pension and other postretirement benefits | 18 | 18 | |||||
Net cash provided by operating activities | 338 | 301 | |||||
Cash Flows From Investing Activities: | |||||||
Capital expenditures | (273 | ) | (299 | ) | |||
Nuclear fuel expenditures | (25 | ) | (52 | ) | |||
Money pool advances, net | 24 | — | |||||
Purchases of securities – nuclear decommissioning trust fund | (97 | ) | (206 | ) | |||
Sales and maturities of securities – nuclear decommissioning trust fund | 89 | 195 | |||||
Other | (3 | ) | (5 | ) | |||
Net cash used in investing activities | (285 | ) | (367 | ) | |||
Cash Flows From Financing Activities: | |||||||
Dividends on common stock | (180 | ) | (200 | ) | |||
Dividends on preferred stock | (2 | ) | (2 | ) | |||
Money pool borrowings, net | — | 67 | |||||
Net cash used in financing activities | (182 | ) | (135 | ) | |||
Net change in cash and cash equivalents | (129 | ) | (201 | ) | |||
Cash and cash equivalents at beginning of year | 148 | 201 | |||||
Cash and cash equivalents at end of period | $ | 19 | $ | — |
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Operating Revenues: | |||||||||||||||
Electric | $ | 368 | $ | 437 | $ | 728 | $ | 868 | |||||||
Gas | 146 | 127 | 470 | 420 | |||||||||||
Other | 2 | — | 2 | — | |||||||||||
Total operating revenues | 516 | 564 | 1,200 | 1,288 | |||||||||||
Operating Expenses: | |||||||||||||||
Purchased power | 80 | 162 | 207 | 352 | |||||||||||
Gas purchased for resale | 61 | 44 | 254 | 227 | |||||||||||
Other operations and maintenance | 196 | 186 | 372 | 354 | |||||||||||
Depreciation and amortization | 62 | 55 | 123 | 110 | |||||||||||
Taxes other than income taxes | 30 | 31 | 72 | 70 | |||||||||||
Total operating expenses | 429 | 478 | 1,028 | 1,113 | |||||||||||
Operating Income | 87 | 86 | 172 | 175 | |||||||||||
Other Income and Expenses: | |||||||||||||||
Miscellaneous income | 2 | 2 | 3 | 3 | |||||||||||
Miscellaneous expense | 1 | 2 | 4 | 13 | |||||||||||
Total other income (expense) | 1 | — | (1 | ) | (10 | ) | |||||||||
Interest Charges | 34 | 31 | 65 | 64 | |||||||||||
Income Before Income Taxes | 54 | 55 | 106 | 101 | |||||||||||
Income Taxes | 22 | 22 | 42 | 40 | |||||||||||
Net Income | 32 | 33 | 64 | 61 | |||||||||||
Other Comprehensive Loss, Net of Taxes: | |||||||||||||||
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $-, $(1), $(1), and $(1), respectively | (1 | ) | (1 | ) | (2 | ) | (2 | ) | |||||||
Comprehensive Income | $ | 31 | $ | 32 | $ | 62 | $ | 59 | |||||||
Net Income | $ | 32 | $ | 33 | $ | 64 | $ | 61 | |||||||
Preferred Stock Dividends | 1 | 1 | 2 | 2 | |||||||||||
Net Income Available to Common Stockholder | $ | 31 | $ | 32 | $ | 62 | $ | 59 |
June 30, 2013 | December 31, 2012 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 98 | $ | — | |||
Accounts receivable – trade (less allowance for doubtful accounts of $16 and $12, respectively) | 185 | 182 | |||||
Accounts receivable – affiliates | 13 | 10 | |||||
Unbilled revenue | 83 | 146 | |||||
Miscellaneous accounts receivable | 18 | 22 | |||||
Materials and supplies | 141 | 173 | |||||
Current regulatory assets | 61 | 84 | |||||
Current accumulated deferred income taxes, net | 82 | 85 | |||||
Other current assets | 29 | 47 | |||||
Total current assets | 710 | 749 | |||||
Property and Plant, Net | 5,216 | 5,052 | |||||
Investments and Other Assets: | |||||||
Tax receivable – Genco | 38 | 39 | |||||
Goodwill | 411 | 411 | |||||
Regulatory assets | 908 | 934 | |||||
Other assets | 83 | 97 | |||||
Total investments and other assets | 1,440 | 1,481 | |||||
TOTAL ASSETS | $ | 7,366 | $ | 7,282 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current Liabilities: | |||||||
Current maturities of long-term debt | $ | 150 | $ | 150 | |||
Borrowings from money pool | — | 24 | |||||
Accounts and wages payable | 184 | 146 | |||||
Accounts payable – affiliates | 91 | 86 | |||||
Taxes accrued | 13 | 18 | |||||
Customer deposits | 85 | 85 | |||||
Mark-to-market derivative liabilities | 55 | 77 | |||||
Current environmental remediation | 56 | 37 | |||||
Current regulatory liabilities | 110 | 82 | |||||
Other current liabilities | 79 | 92 | |||||
Total current liabilities | 823 | 797 | |||||
Long-term Debt, Net | 1,577 | 1,577 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes, net | 1,082 | 1,025 | |||||
Accumulated deferred investment tax credits | 5 | 5 | |||||
Regulatory liabilities | 687 | 672 | |||||
Pension and other postretirement benefits | 416 | 406 | |||||
Environmental remediation | 196 | 216 | |||||
Other deferred credits and liabilities | 149 | 183 | |||||
Total deferred credits and other liabilities | 2,535 | 2,507 | |||||
Commitments and Contingencies (Notes 3, 9 and 10) | |||||||
Stockholders’ Equity: | |||||||
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | — | — | |||||
Other paid-in capital | 1,965 | 1,965 | |||||
Preferred stock not subject to mandatory redemption | 62 | 62 | |||||
Retained earnings | 392 | 360 | |||||
Accumulated other comprehensive income | 12 | 14 | |||||
Total stockholders’ equity | 2,431 | 2,401 | |||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 7,366 | $ | 7,282 |
Six months ended June 30, | |||||||
2013 | 2012 | ||||||
Cash Flows From Operating Activities: | |||||||
Net income | $ | 64 | $ | 61 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | 121 | 105 | |||||
Amortization of debt issuance costs and premium/discounts | 7 | 4 | |||||
Deferred income taxes and investment tax credits, net | 61 | 63 | |||||
Other | (4 | ) | (5 | ) | |||
Changes in assets and liabilities: | |||||||
Receivables | 62 | 62 | |||||
Materials and supplies | 50 | 59 | |||||
Accounts and wages payable | 46 | 13 | |||||
Taxes accrued | (6 | ) | (1 | ) | |||
Assets, other | (4 | ) | (3 | ) | |||
Liabilities, other | (18 | ) | 3 | ||||
Pension and other postretirement benefits | 15 | (5 | ) | ||||
Counterparty collateral, net | 32 | 4 | |||||
Net cash provided by operating activities | 426 | 360 | |||||
Cash Flows From Investing Activities: | |||||||
Capital expenditures | (283 | ) | (184 | ) | |||
Money pool advances, net | — | (67 | ) | ||||
Other | 4 | 4 | |||||
Net cash used in investing activities | (279 | ) | (247 | ) | |||
Cash Flows From Financing Activities: | |||||||
Dividends on common stock | (30 | ) | (75 | ) | |||
Dividends on preferred stock | (2 | ) | (2 | ) | |||
Money pool borrowings, net | (24 | ) | — | ||||
Advances received for construction | 7 | 3 | |||||
Net cash used in financing activities | (49 | ) | (74 | ) | |||
Net change in cash and cash equivalents | 98 | 39 | |||||
Cash and cash equivalents at beginning of year | — | 21 | |||||
Cash and cash equivalents at end of period | $ | 98 | $ | 60 |
• | Union Electric Company, or Ameren Missouri, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. |
• | Ameren Illinois Company, or Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. |
• | AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes. |
Performance Share Units | |||||
Share Units | Weighted-average Fair Value Per Unit at Grant Date | ||||
Nonvested as of January 1, 2013 | 1,192,487 | $ | 33.56 | ||
Granted(a) | 834,919 | 31.19 | |||
Forfeitures | (7,757 | ) | 32.66 | ||
Vested(b) | (129,226 | ) | 31.27 | ||
Nonvested as of June 30, 2013 | 1,890,423 | $ | 32.68 |
(a) | Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2013 under the 2006 Plan. |
(b) | Share units vested due to the attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period. |
Three Months | Six Months | |||||||||
2013 | 2012 | 2013 | 2012 | |||||||
Ameren Missouri | $ | — | $ | (a) | $ | (a) | $ | (a) | ||
Ameren Illinois | 3 | (a) | 7 | (a) | ||||||
Ameren | $ | 3 | $ | (a) | $ | 7 | $ | (a) |
(a) | Less than $1 million. |
Three Months | Six Months | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Ameren Missouri | $ | 38 | $ | 38 | $ | 71 | $ | 65 | |||||||
Ameren Illinois | 11 | 10 | 33 | 28 | |||||||||||
Ameren | $ | 49 | $ | 48 | $ | 104 | $ | 93 |
Three Months | Six Months | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Ameren: | |||||||||||||||
Noncontrolling interests, beginning of period (a) | $ | 151 | $ | 147 | $ | 151 | $ | 149 | |||||||
Net income from continuing operations attributable to noncontrolling interests | 1 | 1 | 3 | 3 | |||||||||||
Net income (loss) from discontinued operations attributable to noncontrolling interests | — | (2 | ) | — | (4 | ) | |||||||||
Dividends paid to noncontrolling interest holders | (1 | ) | (1 | ) | (3 | ) | (3 | ) | |||||||
Noncontrolling interests, end of period (a) | $ | 151 | $ | 145 | $ | 151 | $ | 145 |
(a) | Includes the 20% EEI ownership interest not owned by Ameren. The assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Current assets of discontinued operations” and “Current liabilities of discontinued operations.” The 20% ownership interest not owned by Ameren was included in “Noncontrolling interests” on Ameren’s June 30, 2013, and December 31, 2012 balance sheets. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information. |
Three Months | Six months | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Operating revenues | $ | 303 | $ | 258 | $ | 567 | $ | 504 | ||||||||
Operating expenses | (310 | ) | (238 | ) | (725 | ) | (a) | (1,064 | ) | (b) | ||||||
Operating income (loss) | (7 | ) | 20 | (158 | ) | (560 | ) | |||||||||
Other income (loss) | 1 | — | (1 | ) | — | |||||||||||
Interest charges | (11 | ) | (14 | ) | (22 | ) | (29 | ) | ||||||||
Income (loss) before income taxes | (17 | ) | 6 | (181 | ) | (589 | ) | |||||||||
Income tax (expense) benefit | 7 | 42 | (28 | ) | 195 | |||||||||||
Income (loss) from discontinued operations, net of taxes | $ | (10 | ) | $ | 48 | $ | (209 | ) | $ | (394 | ) |
(a) | Includes a noncash pretax impairment charge of $168 million for the six months ended June 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. |
(b) | Includes a noncash pretax asset impairment charge of $628 million to reduce the carrying value of AERG’s Duck Creek energy center to its estimated fair value under held and used accounting guidance. |
June 30, 2013 | December 31, 2012 | ||||||
Current assets of discontinued operations | |||||||
Cash and cash equivalents | $ | 25 | $ | 25 | |||
Accounts receivable and unbilled revenue | 102 | 102 | |||||
Materials and supplies | 119 | 134 | |||||
Mark-to-market derivative assets | 111 | 102 | |||||
Property and plant, net | 615 | 748 | |||||
Accumulated deferred income taxes, net | 380 | 373 | |||||
Other assets | 134 | 116 | |||||
Total current assets of discontinued operations | $ | 1,486 | $ | 1,600 | |||
Current liabilities of discontinued operations | |||||||
Accounts payable and other current obligations | $ | 142 | $ | 133 | |||
Mark-to-market derivative liabilities | 70 | 63 | |||||
Long-term debt, net | 824 | 824 | |||||
Asset retirement obligations | 87 | 78 | |||||
Pension and other postretirement benefits | 37 | 40 | |||||
Other liabilities | 23 | 28 | |||||
Total current liabilities of discontinued operations | $ | 1,183 | $ | 1,166 | |||
Accumulated other comprehensive income(a) | $ | 8 | $ | 19 | |||
Noncontrolling interest(b) | $ | 8 | $ | 8 |
(a) | Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s June 30, 2013, and December 31, 2012, balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s balance sheet either before or at the closing of the New AER divestiture. |
(b) | The 20% ownership interest of EEI not owned by Ameren remains in “Noncontrolling interests” on Ameren’s June 30, 2013, and December 31, 2012, balance sheets. This noncontrolling interest will be removed from Ameren’s balance sheet at the closing of the New AER divestiture. |
Required Ratio | Actual Ratio | ||
Interest coverage ratio- restricted payment (a) | ≥1.75 | 1.60 | |
Interest coverage ratio- additional indebtedness (b) | ≥2.50 | 1.60 | |
Debt-to-capital ratio- additional indebtedness (b) | ≤60% | 50 | % |
(a) | As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. Investments in the non-state-regulated subsidiary money pool and repayments of non-state-regulated subsidiary money pool borrowings are not subject to this incurrence test. |
(b) | Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Non-state-regulated subsidiary money pool borrowings are defined as permitted indebtedness and are not subject to these incurrence tests. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests. |
Required Interest Coverage Ratio(a) | Actual Interest Coverage Ratio | Bonds Issuable(b) | Required Dividend Coverage Ratio(c) | Actual Dividend Coverage Ratio | Preferred Stock Issuable | |||||||||
Ameren Missouri | ≥2.0 | 4.4 | $ | 3,633 | ≥2.5 | 110.9 | $ | 2,118 | ||||||
Ameren Illinois | ≥2.0 | 7.3 | 3,581 | (d) | ≥1.5 | 2.7 | 203 |
(a) | Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. |
(b) | Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $485 million and $645 million at Ameren Missouri and Ameren Illinois, respectively. |
(c) | Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. |
(d) | Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture. |
Three Months | Six Months | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Ameren:(a) | ||||||||||||||||
Miscellaneous income: | ||||||||||||||||
Allowance for equity funds used during construction | $ | 8 | $ | 8 | $ | 16 | $ | 17 | ||||||||
Interest income on industrial development revenue bonds | 7 | 7 | 14 | 14 | ||||||||||||
Interest and dividend income | 1 | 4 | 1 | 4 | ||||||||||||
Other | — | — | — | 1 | ||||||||||||
Total miscellaneous income | $ | 16 | $ | 19 | $ | 31 | $ | 36 | ||||||||
Miscellaneous expense: | ||||||||||||||||
Donations | $ | 1 | $ | 3 | $ | 5 | $ | 15 | (b) | |||||||
Other | 4 | 4 | 8 | 7 | ||||||||||||
Total miscellaneous expense | $ | 5 | $ | 7 | $ | 13 | $ | 22 | ||||||||
Ameren Missouri: | ||||||||||||||||
Miscellaneous income: | ||||||||||||||||
Allowance for equity funds used during construction | $ | 7 | $ | 7 | $ | 14 | $ | 15 | ||||||||
Interest income on industrial development revenue bonds | 7 | 7 | 14 | 14 | ||||||||||||
Interest and dividend income | — | 4 | — | 4 | ||||||||||||
Total miscellaneous income | $ | 14 | $ | 18 | $ | 28 | $ | 33 | ||||||||
Miscellaneous expense: | ||||||||||||||||
Donations | $ | 1 | $ | 3 | $ | 3 | $ | 5 | ||||||||
Other | 2 | 1 | 5 | 2 | ||||||||||||
Total miscellaneous expense | $ | 3 | $ | 4 | $ | 8 | $ | 7 | ||||||||
Ameren Illinois: | ||||||||||||||||
Miscellaneous income: | ||||||||||||||||
Allowance for equity funds used during construction | $ | 1 | $ | 1 | $ | 2 | $ | 2 | ||||||||
Interest and dividend income | 1 | — | 1 | — | ||||||||||||
Other | — | 1 | — | 1 | ||||||||||||
Total miscellaneous income | $ | 2 | $ | 2 | $ | 3 | $ | 3 | ||||||||
Miscellaneous expense: | ||||||||||||||||
Donations | $ | — | $ | — | $ | 3 | $ | 10 | (b) | |||||||
Other | 1 | 2 | 1 | 3 | ||||||||||||
Total miscellaneous expense | $ | 1 | $ | 2 | $ | 4 | $ | 13 |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
(b) | Includes Ameren Illinois’ one-time $7.5 million donation to the Illinois Science and Energy Innovation Trust pursuant to the IEIMA as a result of Ameren Illinois’ 2012 election to participate in the formula ratemaking process. |
• | 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. |
Quantity (in millions, except as indicated) | |||||||||||||||||
Commodity | Accrual & NPNS Contracts(a) | Other Derivatives(b) | Derivatives That Qualify for Regulatory Deferral(c) | ||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||
Coal (in tons) | |||||||||||||||||
Ameren Missouri & Ameren | 85 | 96 | (d) | (d) | (d) | (d) | |||||||||||
Fuel oils (in gallons)(e) | |||||||||||||||||
Ameren Missouri & Ameren | (d) | (d) | (d) | (d) | 58 | 70 | |||||||||||
Natural gas (in mmbtu) | |||||||||||||||||
Ameren Missouri | — | 4 | — | — | 30 | 19 | |||||||||||
Ameren Illinois | 9 | 16 | (d) | (d) | 127 | 128 | |||||||||||
Ameren | 9 | 20 | — | — | 157 | 147 | |||||||||||
Power (in megawatthours) | |||||||||||||||||
Ameren Missouri | 3 | 3 | 1 | 2 | 7 | 9 | |||||||||||
Ameren Illinois | 18 | 21 | (d) | (d) | 11 | 14 | |||||||||||
Ameren | 21 | 24 | 1 | 2 | 18 | 23 | |||||||||||
Renewable energy credits(f) | |||||||||||||||||
Ameren Missouri | 3 | 3 | (d) | (d) | (d) | (d) | |||||||||||
Ameren Illinois | 11 | 12 | (d) | (d) | (d) | (d) | |||||||||||
Ameren | 14 | 15 | (d) | (d) | (d) | (d) | |||||||||||
Uranium (pounds in thousands) | |||||||||||||||||
Ameren Missouri & Ameren | 4,671 | 5,142 | (d) | (d) | 514 | 446 |
(a) | Accrual contracts include commodity contracts that do not qualify as derivatives. As of June 30, 2013, these contracts ran through December 2017, March 2015, September 2024, May 2032, and October 2024 for coal, natural gas, power, renewable energy credits, and uranium, respectively. |
(b) | As of June 30, 2013, these contracts ran through December 2014 for power. |
(c) | As of June 30, 2013, these contracts ran through October 2015, October 2019, May 2032, and May 2015 for fuel oils, natural gas, power, and uranium, respectively. |
(d) | Not applicable. |
(e) | Fuel oils consist of heating oil, ultra-low sulfur diesel, and crude oil. |
(f) | A renewable energy credit is created for every one megawatthour of renewable energy generated. The Ameren Companies’ contracts include renewable energy credits from solar and wind-generated power. |
Balance Sheet Location | Ameren | Ameren Missouri | Ameren Illinois | |||||||
2013 | ||||||||||
Derivative assets not designated as hedging instruments(a) | ||||||||||
Commodity contracts: | ||||||||||
Fuel oils | Other current assets | $ | 5 | $ | 5 | $ | — | |||
Other assets | 2 | 2 | — | |||||||
Natural gas | Other current assets | 2 | 1 | 1 | ||||||
Other assets | 1 | — | 1 | |||||||
Power | Other current assets | 45 | 44 | 1 | ||||||
Other assets | 2 | 1 | 1 | |||||||
Total assets | $ | 57 | $ | 53 | $ | 4 | ||||
Derivative liabilities not designated as hedging instruments(a) | ||||||||||
Commodity contracts: | ||||||||||
Fuel oils | MTM derivative liabilities | $ | 2 | $ | (b) | $ | — | |||
Other current liabilities | — | 2 | — | |||||||
Other deferred credits and liabilities | 2 | 2 | — | |||||||
Natural gas | MTM derivative liabilities | 52 | (b) | 45 | ||||||
Other current liabilities | — | 7 | — | |||||||
Other deferred credits and liabilities | 33 | 5 | 28 | |||||||
Power | MTM derivative liabilities | 18 | (b) | 10 | ||||||
Other current liabilities | — | 8 | — | |||||||
Other deferred credits and liabilities | 73 | 1 | 72 | |||||||
Uranium | MTM derivative liabilities | 3 | (b) | — | ||||||
Other current liabilities | — | 3 | — | |||||||
Total liabilities | $ | 183 | $ | 28 | $ | 155 | ||||
2012 | ||||||||||
Derivative assets not designated as hedging instruments(a) | ||||||||||
Commodity contracts: | ||||||||||
Fuel oils | Other current assets | $ | 8 | $ | 8 | $ | — | |||
Other assets | 4 | 4 | — | |||||||
Natural gas | Other current assets | 1 | — | 1 | ||||||
Other assets | 1 | 1 | — | |||||||
Power | Other current assets | 14 | 14 | — | ||||||
Other assets | 1 | 1 | — | |||||||
Total assets | $ | 29 | $ | 28 | $ | 1 | ||||
Derivative liabilities not designated as hedging instruments(a) | ||||||||||
Commodity contracts: | ||||||||||
Fuel oils | MTM derivative liabilities | $ | 2 | $ | (b) | $ | — | |||
Other current liabilities | — | 2 | — | |||||||
Other deferred credits and liabilities | 2 | 2 | — | |||||||
Natural gas | MTM derivative liabilities | 64 | (b) | 56 | ||||||
Other current liabilities | — | 8 | — | |||||||
Other deferred credits and liabilities | 45 | 7 | 38 | |||||||
Power | MTM derivative liabilities | 25 | (b) | 21 | ||||||
Other current liabilities | — | 4 | — | |||||||
Other deferred credits and liabilities | 90 | — | 90 | |||||||
Uranium | MTM derivative liabilities | 1 | (b) | — | ||||||
Other current liabilities | — | 1 | — | |||||||
Other deferred credits and liabilities | 1 | 1 | — | |||||||
Total liabilities | $ | 230 | $ | 25 | $ | 205 |
(a) | Includes derivatives subject to regulatory deferral. |
(b) | Balance sheet line item not applicable to registrant. |
Ameren | Ameren Missouri | Ameren Illinois | |||||||||
2013 | |||||||||||
Cumulative gains (losses) deferred in regulatory liabilities or assets: | |||||||||||
Fuel oils derivative contracts(a) | $ | — | $ | — | $ | — | |||||
Natural gas derivative contracts(b) | (83 | ) | (12 | ) | (71 | ) | |||||
Power derivative contracts(c) | (43 | ) | 37 | (80 | ) | ||||||
Uranium derivative contracts(d) | (3 | ) | (3 | ) | — | ||||||
2012 | |||||||||||
Cumulative gains (losses) deferred in regulatory liabilities or assets: | |||||||||||
Fuel oils derivative contracts(a) | $ | 4 | $ | 4 | $ | — | |||||
Natural gas derivative contracts(b) | (107 | ) | (14 | ) | (93 | ) | |||||
Power derivative contracts(c) | (99 | ) | 12 | (111 | ) | ||||||
Uranium derivative contracts(d) | (2 | ) | (2 | ) | — |
(a) | Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through October 2015 as of June 30, 2013. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013. |
(b) | Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2016 at Ameren Illinois as of June 30, 2013. Current gains deferred as regulatory liabilities include $2 million, $1 million, and $1 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $52 million, $7 million, and $45 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2013. |
(c) | Represents net gains (losses) associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri as of June 30, 2013. Current gains deferred as regulatory liabilities include $44 million, $43 million, and $1 million at Ameren, Ameren Missouri, and Ameren Illinois, respectively, as of June 30, 2013. Current losses deferred as regulatory assets include $16 million, $6 million, and $10 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2013. |
(d) | Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through May 2015 as of June 30, 2013. Current losses deferred as regulatory assets include $3 million and $3 million at Ameren and Ameren Missouri, respectively, as of June 30, 2013. |
Gross Amounts Not Offset in the Balance Sheet | ||||||||||||||||
Gross Amounts Recognized in the Balance Sheet | Derivative Instruments | Cash Collateral Received/Posted(a) | Net Amount | |||||||||||||
2013 | ||||||||||||||||
Commodity contracts eligible to be offset: | ||||||||||||||||
Assets: | ||||||||||||||||
Ameren | $ | 57 | $ | 15 | $ | — | $ | 42 | ||||||||
Ameren Missouri | 53 | 13 | — | 40 | ||||||||||||
Ameren Illinois | 4 | 2 | — | 2 | ||||||||||||
Liabilities: | ||||||||||||||||
Ameren | $ | 183 | $ | 15 | $ | 32 | $ | 136 | ||||||||
Ameren Missouri | 28 | 13 | 6 | 9 | ||||||||||||
Ameren Illinois | 155 | 2 | 26 | 127 | ||||||||||||
2012 | ||||||||||||||||
Commodity contracts eligible to be offset: | ||||||||||||||||
Assets: | ||||||||||||||||
Ameren | $ | 29 | $ | 10 | $ | — | $ | 19 | ||||||||
Ameren Missouri | 28 | 9 | — | 19 | ||||||||||||
Ameren Illinois | 1 | 1 | — | — | ||||||||||||
Liabilities: | ||||||||||||||||
Ameren | $ | 230 | $ | 10 | $ | 65 | $ | 155 | ||||||||
Ameren Missouri | 25 | 9 | 7 | 9 | ||||||||||||
Ameren Illinois | 205 | 1 | 58 | 146 |
(a) | Cash collateral received reduces gross asset balances and cash collateral posted reduces gross liability balances. |
Commodity Marketing Companies | Electric Utilities | Financial Companies | Municipalities/ Cooperatives | Oil and Gas Companies | Total | ||||||||||||||||||
2013 | |||||||||||||||||||||||
Ameren Missouri | $ | 3 | $ | 5 | $ | 16 | $ | 5 | $ | — | $ | 29 | |||||||||||
Ameren Illinois | — | — | 1 | — | 1 | 2 | |||||||||||||||||
Ameren | $ | 3 | $ | 5 | $ | 17 | $ | 5 | $ | 1 | $ | 31 | |||||||||||
2012 | |||||||||||||||||||||||
Ameren Missouri | $ | 2 | $ | 3 | $ | 14 | $ | 3 | $ | — | $ | 22 | |||||||||||
Ameren Illinois | — | — | 1 | — | — | 1 | |||||||||||||||||
Ameren | $ | 2 | $ | 3 | $ | 15 | $ | 3 | $ | — | $ | 23 |
Commodity Marketing Companies | Electric Utilities | Financial Companies | Municipalities/ Cooperatives | Oil and Gas Companies | Total | ||||||||||||||||||
2013 | |||||||||||||||||||||||
Ameren Missouri | $ | 1 | $ | 4 | $ | 2 | $ | 3 | $ | — | $ | 10 | |||||||||||
Ameren Illinois | — | — | — | — | — | — | |||||||||||||||||
Ameren | $ | 1 | $ | 4 | $ | 2 | $ | 3 | $ | — | $ | 10 | |||||||||||
2012 | |||||||||||||||||||||||
Ameren Missouri | $ | 1 | $ | 1 | $ | 10 | $ | 3 | $ | — | $ | 15 | |||||||||||
Ameren Illinois | — | — | — | — | — | — | |||||||||||||||||
Ameren | $ | 1 | $ | 1 | $ | 10 | $ | 3 | $ | — | $ | 15 |
Aggregate Fair Value of Derivative Liabilities(a) | Cash Collateral Posted | Potential Aggregate Amount of Additional Collateral Required(b) | |||||||||
2013 | |||||||||||
Ameren Missouri | $ | 76 | $ | 1 | $ | 45 | |||||
Ameren Illinois | 116 | 26 | 82 | ||||||||
Ameren | $ | 192 | $ | 27 | $ | 127 | |||||
2012 | |||||||||||
Ameren Missouri | $ | 78 | $ | 3 | $ | 71 | |||||
Ameren Illinois | 148 | 58 | 84 | ||||||||
Ameren | $ | 226 | $ | 61 | $ | 155 |
(a) | Prior to consideration of master trading and netting agreements and including NPNS contract exposures. |
(b) | As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the netting effects of such agreements. |
Gain (Loss) Recognized in Regulatory Liabilities or Regulatory Assets | |||||||||||||||||
Three Months | Six Months | ||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
Ameren | Fuel oils | $ | (4 | ) | $ | (19 | ) | $ | (4 | ) | $ | (14 | ) | ||||
Natural gas | (12 | ) | 46 | 24 | 28 | ||||||||||||
Power(a) | 36 | (1 | ) | 56 | (163 | ) | |||||||||||
Uranium | (1 | ) | — | (1 | ) | — | |||||||||||
Total | $ | 19 | $ | 26 | $ | 75 | $ | (149 | ) | ||||||||
Ameren Missouri | Fuel oils | $ | (4 | ) | $ | (19 | ) | $ | (4 | ) | $ | (14 | ) | ||||
Natural gas | (2 | ) | 5 | 2 | 3 | ||||||||||||
Power | 35 | 4 | 25 | 3 | |||||||||||||
Uranium | (1 | ) | — | (1 | ) | — | |||||||||||
Total | $ | 28 | $ | (10 | ) | $ | 22 | $ | (8 | ) | |||||||
Ameren Illinois | Natural gas | $ | (10 | ) | $ | 41 | $ | 22 | $ | 25 | |||||||
Power | 1 | 63 | 31 | (81 | ) | ||||||||||||
Total | $ | (9 | ) | $ | 104 | $ | 53 | $ | (56 | ) |
(a) | Amounts include intercompany eliminations. |
Fair Value | Weighted | ||||||||||
Assets | Liabilities | Valuation Technique | Unobservable Input | Range | Average | ||||||
Level 3 Derivative asset and liability - commodity contracts(a): | |||||||||||
Ameren | Fuel oils | $ | 7 | $ | (4 | ) | Option model | Volatilities(%)(b) | 8 - 32 | 20 | |
Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.26 - 3 | 2 | ||||||||
Natural gas | 2 | (1 | ) | Option model | Volatilities(%)(b) | 1 - 31 | 24 | ||||
Nodal basis($/mmbtu)(c) | (0.35) - (0.06) | (0.3) | |||||||||
Discounted cash flow | Nodal basis($/mmbtu)(c) | (0.1) - 0 | 0 | ||||||||
Counterparty credit risk(%)(c)(d) | 0.22 - 2 | 1 | |||||||||
Ameren credit risk(%)(c)(d) | 3 | (f) | |||||||||
Power(e) | 44 | (87 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c) | 25 - 49 | 32 | ||||
Estimated auction price for FTRs($/MW)(b) | (767) - 1,790 | 252 | |||||||||
Nodal basis($/MWh)(c) | (4) - (1) | (3) | |||||||||
Counterparty credit risk(%)(c)(d) | 0.22 - 7 | 3 | |||||||||
Ameren credit risk(%)(c)(d) | 3 | (f) | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 5 - 8 | 6 | ||||||||
Escalation rate(%)(b)(g) | 4 - 5 | 4 | |||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 | ||||||||
Uranium | — | (3 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 40 - 44 | 40 | ||||
Ameren Missouri | Fuel oils | $ | 7 | $ | (4 | ) | Option model | Volatilities(%)(b) | 8 - 32 | 20 | |
Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.26 - 3 | 2 | ||||||||
Natural gas | — | (1 | ) | Option model | Volatilities(%)(b) | 1 - 31 | 24 | ||||
Nodal basis($/mmbtu)(c) | (0.35) - (0.06) | (0.3) | |||||||||
Discounted cash flow | Nodal basis($/mmbtu)(c) | (0.1) - 0 | (0.1) | ||||||||
Counterparty credit risk(%)(c)(d) | 0.22 - 2 | 1 | |||||||||
Ameren Missouri credit risk(%)(c)(d) | 3 | (f) | |||||||||
Power(e) | 42 | (5 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c) | 25 - 49 | 38 | ||||
Estimated auction price for FTRs($/MW)(b) | (767) - 1,790 | 252 | |||||||||
Nodal basis($/MWh)(c) | (4) - (1) | (2) | |||||||||
Counterparty credit risk(%)(c)(d) | 0.22 - 3 | 3 | |||||||||
Ameren Missouri credit risk(%)(c)(d) | 3 | (f) | |||||||||
Uranium | — | (3 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 40 - 44 | 40 | ||||
Ameren Illinois | Natural gas | $ | 2 | $ | — | Option model | Volatilities(%)(b) | 1 - 31 | 27 | ||
Nodal basis($/mmbtu)(c) | (0.3) - (0.27) | (0.28) | |||||||||
Discounted cash flow | Nodal basis($/mmbtu)(c) | (0.1) - 0 | 0 | ||||||||
Counterparty credit risk(%)(c)(d) | 0.69 - 2 | 1 | |||||||||
Ameren Illinois credit risk(%)(c)(d) | 3 | (f) | |||||||||
Power(e) | 2 | (82 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(b) | 26 - 39 | 30 | ||||
Nodal basis($/MWh)(b) | (4) - (1) | (3) | |||||||||
Counterparty credit risk(%)(c)(d) | 7 | (f) | |||||||||
Ameren Illinois credit risk(%)(c)(d) | 3 | (f) | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 5 - 8 | 6 | ||||||||
Escalation rate(%)(b)(g) | 4 - 5 | 4 | |||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
(d) | Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances. |
(e) | Power valuations utilize visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand. |
(f) | Not applicable. |
(g) | Escalation rate applies to power prices 2026 and beyond. |
Fair Value | Weighted | ||||||||||
Assets | Liabilities | Valuation Technique | Unobservable Input | Range | Average | ||||||
Level 3 Derivative asset and liability - commodity contracts(a): | |||||||||||
Ameren | Fuel oils | $ | 8 | $ | (3 | ) | Discounted cash flow | Escalation rate(%)(b) | .21 - .60 | .44 | |
Counterparty credit risk(%)(c)(d) | .12 - 1 | 1 | |||||||||
Ameren credit risk(%)(c)(d) | 2 | (e) | |||||||||
Option model | Volatilities(%)(b) | 7 - 27 | 24 | ||||||||
Power(f) | 14 | (114 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c) | 22 - 47 | 31 | ||||
Estimated auction price for FTRs($/MW)(b) | (281) - 1,851 | 178 | |||||||||
Nodal basis($/MWh)(c) | (5) - (1) | (3) | |||||||||
Counterparty credit risk(%)(c)(d) | .22 - 1 | 1 | |||||||||
Ameren credit risk(%)(c)(d) | 2 - 5 | 5 | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 8 | 6 | ||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 | ||||||||
Uranium | — | (2 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 43 - 46 | 44 | ||||
Ameren Missouri | Fuel oils | $ | 8 | $ | (3 | ) | Discounted cash flow | Escalation rate(%)(b) | .21 - .60 | .44 | |
Counterparty credit risk(%)(c)(d) | .12 - 1 | 1 | |||||||||
Ameren Missouri credit risk(%)(c)(d) | 2 | (e) | |||||||||
Option model | Volatilities(%)(b) | 7 - 27 | 24 | ||||||||
Power(f) | 14 | (3 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(c) | 24 - 56 | 36 | ||||
Estimated auction price for FTRs($/MW)(b) | (281) - 1,851 | 178 | |||||||||
Nodal basis($/MWh)(c) | (5) - (1) | (2) | |||||||||
Counterparty credit risk(%)(c)(d) | .22 - 1 | 1 | |||||||||
Ameren Missouri credit risk(%)(c)(d) | 2 | (e) | |||||||||
Uranium | — | (2 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 43 - 46 | 44 | ||||
Ameren Illinois | Power(f) | $ | — | $ | (111 | ) | Discounted cash flow | Average forward peak and off-peak power pricing - forwards/swaps($/MWh)(b) | 22 - 47 | 30 | |
Nodal basis($/MWh)(b) | (5) - (1) | (3) | |||||||||
Ameren Illinois credit risk(%)(c)(d) | 5 | (e) | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 8 | 6 | ||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
(d) | Counterparty credit risk is only applied to counterparties with derivative asset balances. Ameren, Ameren Missouri, and Ameren Illinois credit risk is only applied to counterparties with derivative liability balances. |
(e) | Not applicable. |
(f) | Power valuations utilize visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 utilize fundamentally modeled pricing by month for peak and off-peak demand. |
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||||
Assets: | |||||||||||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | — | $ | — | $ | 7 | $ | 7 | |||||||||
Natural gas | — | 1 | 2 | 3 | |||||||||||||
Power | — | 3 | 44 | 47 | |||||||||||||
Total derivative assets - commodity contracts | $ | — | $ | 4 | $ | 53 | $ | 57 | |||||||||
Nuclear Decommissioning Trust Fund(b): | |||||||||||||||||
Cash and cash equivalents | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||
Equity securities: | |||||||||||||||||
U.S. large capitalization | 294 | — | — | 294 | |||||||||||||
Debt securities: | |||||||||||||||||
Corporate bonds | — | 40 | — | 40 | |||||||||||||
Municipal bonds | — | 1 | — | 1 | |||||||||||||
U.S. treasury and agency securities | — | 91 | — | 91 | |||||||||||||
Asset-backed securities | — | 10 | — | 10 | |||||||||||||
Other | — | 1 | — | 1 | |||||||||||||
Total Nuclear Decommissioning Trust Fund | $ | 297 | $ | 143 | $ | — | $ | 440 | |||||||||
Total Ameren | $ | 297 | $ | 147 | $ | 53 | $ | 497 | |||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Missouri | Fuel oils | $ | — | $ | — | $ | 7 | $ | 7 | ||||||||
Natural gas | — | 1 | — | 1 | |||||||||||||
Power | — | 3 | 42 | 45 | |||||||||||||
Total derivative assets - commodity contracts | $ | — | $ | 4 | $ | 49 | $ | 53 | |||||||||
Nuclear Decommissioning Trust Fund(b): | |||||||||||||||||
Cash and cash equivalents | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||
Equity securities: | |||||||||||||||||
U.S. large capitalization | 294 | — | — | 294 | |||||||||||||
Debt securities: | |||||||||||||||||
Corporate bonds | — | 40 | — | 40 | |||||||||||||
Municipal bonds | — | 1 | — | 1 | |||||||||||||
U.S. treasury and agency securities | — | 91 | — | 91 | |||||||||||||
Asset-backed securities | — | 10 | — | 10 | |||||||||||||
Other | — | 1 | — | 1 | |||||||||||||
Total Nuclear Decommissioning Trust Fund | $ | 297 | $ | 143 | $ | — | $ | 440 | |||||||||
Total Ameren Missouri | $ | 297 | $ | 147 | $ | 49 | $ | 493 | |||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Illinois | Natural gas | $ | — | $ | — | $ | 2 | $ | 2 | ||||||||
Power | — | — | 2 | 2 | |||||||||||||
Total Ameren Illinois | $ | — | $ | — | $ | 4 | $ | 4 | |||||||||
Liabilities: | |||||||||||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | — | $ | — | $ | 4 | $ | 4 | |||||||||
Natural gas | 5 | 79 | 1 | 85 | |||||||||||||
Power | — | 4 | 87 | 91 | |||||||||||||
Uranium | — | — | 3 | 3 | |||||||||||||
Total Ameren | $ | 5 | $ | 83 | $ | 95 | $ | 183 | |||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Missouri | Fuel oils | $ | — | $ | — | $ | 4 | $ | 4 | ||||||||
Natural gas | 5 | 6 | 1 | 12 | |||||||||||||
Power | — | 4 | 5 | 9 | |||||||||||||
Uranium | — | — | 3 | 3 | |||||||||||||
Total Ameren Missouri | $ | 5 | $ | 10 | $ | 13 | $ | 28 | |||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Illinois | Natural gas | $ | — | $ | 73 | $ | — | $ | 73 | ||||||||
Power | — | — | 82 | 82 | |||||||||||||
Total Ameren Illinois | $ | — | $ | 73 | $ | 82 | $ | 155 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||||
Assets: | |||||||||||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | 4 | $ | — | $ | 8 | $ | 12 | |||||||||
Natural gas | — | 2 | — | 2 | |||||||||||||
Power | — | 1 | 14 | 15 | |||||||||||||
Total derivative assets - commodity contracts | $ | 4 | $ | 3 | $ | 22 | $ | 29 | |||||||||
Nuclear Decommissioning Trust Fund(b): | |||||||||||||||||
Cash and cash equivalents | $ | 1 | $ | — | $ | — | $ | 1 | |||||||||
Equity securities: | |||||||||||||||||
U.S. large capitalization | 264 | — | — | 264 | |||||||||||||
Debt securities: | |||||||||||||||||
Corporate bonds | — | 47 | — | 47 | |||||||||||||
Municipal bonds | — | 1 | — | 1 | |||||||||||||
U.S. treasury and agency securities | — | 81 | — | 81 | |||||||||||||
Asset-backed securities | — | 11 | — | 11 | |||||||||||||
Other | — | 1 | — | 1 | |||||||||||||
Total Nuclear Decommissioning Trust Fund | $ | 265 | $ | 141 | $ | — | $ | 406 | |||||||||
Total Ameren | $ | 269 | $ | 144 | $ | 22 | $ | 435 | |||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Missouri | Fuel oils | $ | 4 | $ | — | $ | 8 | $ | 12 | ||||||||
Natural gas | — | 1 | — | 1 | |||||||||||||
Power | — | 1 | 14 | 15 | |||||||||||||
Total derivative assets - commodity contracts | $ | 4 | $ | 2 | $ | 22 | $ | 28 | |||||||||
Nuclear Decommissioning Trust Fund(b): | |||||||||||||||||
Cash and cash equivalents | $ | 1 | $ | — | $ | — | $ | 1 | |||||||||
Equity securities: | |||||||||||||||||
U.S. large capitalization | 264 | — | — | 264 | |||||||||||||
Debt securities: | |||||||||||||||||
Corporate bonds | — | 47 | — | 47 | |||||||||||||
Municipal bonds | — | 1 | — | 1 | |||||||||||||
U.S. treasury and agency securities | — | 81 | — | 81 | |||||||||||||
Asset-backed securities | — | 11 | — | 11 | |||||||||||||
Other | — | 1 | — | 1 | |||||||||||||
Total Nuclear Decommissioning Trust Fund | $ | 265 | $ | 141 | $ | — | $ | 406 | |||||||||
Total Ameren Missouri | $ | 269 | $ | 143 | $ | 22 | $ | 434 | |||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Illinois | Natural gas | $ | — | $ | 1 | $ | — | $ | 1 |
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||||
Liabilities: | |||||||||||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | 1 | $ | — | $ | 3 | $ | 4 | |||||||||
Natural gas | 7 | 102 | — | 109 | |||||||||||||
Power | — | 1 | 114 | 115 | |||||||||||||
Uranium | — | — | 2 | 2 | |||||||||||||
Total Ameren | $ | 8 | $ | 103 | $ | 119 | $ | 230 | |||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Missouri | Fuel oils | $ | 1 | $ | — | $ | 3 | $ | 4 | ||||||||
Natural gas | 7 | 8 | — | 15 | |||||||||||||
Power | — | 1 | 3 | 4 | |||||||||||||
Uranium | — | — | 2 | 2 | |||||||||||||
Total Ameren Missouri | $ | 8 | $ | 9 | $ | 8 | $ | 25 | |||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Illinois | Natural gas | $ | — | $ | 94 | $ | — | $ | 94 | ||||||||
Power | — | — | 111 | 111 | |||||||||||||
Total Ameren Illinois | $ | — | $ | 94 | $ | 111 | $ | 205 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
Net derivative commodity contracts | |||||||||
Three Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at April 1, 2013 | $ | 5 | $ | (a) | $ | 5 | |||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Total realized and unrealized gains (losses) | (2 | ) | (a) | (2 | ) | ||||
Ending balance at June 30, 2013 | $ | 3 | $ | (a) | $ | 3 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) | |
Natural gas: | |||||||||
Beginning balance at April 1, 2013 | $ | — | $ | 2 | $ | 2 | |||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | — | — | — | ||||||
Total realized and unrealized gains (losses) | — | — | — | ||||||
Purchases | (1 | ) | — | (1 | ) | ||||
Ending balance at June 30, 2013 | $ | (1 | ) | $ | 2 | $ | 1 | ||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | — | $ | (1 | ) | |
Power: | |||||||||
Beginning balance at April 1, 2013 | $ | 2 | $ | (81 | ) | $ | (79 | ) | |
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | 1 | 1 | 2 | ||||||
Total realized and unrealized gains (losses) | 1 | 1 | 2 | ||||||
Purchases | 40 | — | 40 | ||||||
Settlements | (9 | ) | — | (9 | ) | ||||
Transfers out of Level 3 | 3 | — | 3 | ||||||
Ending balance at June 30, 2013 | $ | 37 | $ | (80 | ) | $ | (43 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | 3 | $ | (4 | ) | $ | (1 | ) | |
Uranium: | |||||||||
Beginning balance at April 1, 2013 | $ | (2 | ) | $ | (a) | $ | (2 | ) | |
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Total realized and unrealized gains (losses) | (2 | ) | (a) | (2 | ) | ||||
Settlements | 1 | (a) | 1 | ||||||
Ending balance at June 30, 2013 | $ | (3 | ) | $ | (a) | $ | (3 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) |
(a) | Not applicable. |
Net derivative commodity contracts | |||||||||
Three Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at April 1, 2012 | $ | 7 | $ | (a) | $ | 7 | |||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (4 | ) | (a) | (4 | ) | ||||
Total realized and unrealized gains (losses) | (4 | ) | (a) | (4 | ) | ||||
Purchases | 2 | (a) | 2 | ||||||
Sales | (1 | ) | (a) | (1 | ) | ||||
Settlements | (1 | ) | (a) | (1 | ) | ||||
Ending balance at June 30, 2012 | $ | 3 | $ | (a) | $ | 3 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012 | $ | (2 | ) | $ | (a) | $ | (2 | ) | |
Power(b): | |||||||||
Beginning balance at April 1, 2012 | $ | 20 | $ | (284 | ) | $ | (82 | ) | |
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (4 | ) | (1 | ) | (10 | ) | |||
Total realized and unrealized gains (losses) | (4 | ) | (1 | ) | (10 | ) | |||
Purchases | 22 | — | 22 | ||||||
Settlements | (11 | ) | 64 | (10 | ) | ||||
Transfers out of Level 3 | (1 | ) | — | (1 | ) | ||||
Ending balance at June 30, 2012 | $ | 26 | $ | (221 | ) | $ | (81 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012 | $ | (1 | ) | $ | (6 | ) | $ | 5 | |
Uranium: | |||||||||
Beginning balance at April 1, 2012 | $ | (1 | ) | (a) | $ | (1 | ) | ||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | — | (a) | — | ||||||
Total realized and unrealized gains (losses) | — | (a) | — | ||||||
Ending balance at June 30, 2012 | $ | (1 | ) | (a) | $ | (1 | ) | ||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012 | $ | — | (a) | $ | — |
(a) | Not applicable. |
(b) | Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company. |
Net derivative commodity contracts | |||||||||
Six Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at January 1, 2013 | $ | 5 | $ | (a) | $ | 5 | |||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Total realized and unrealized gains (losses) | (2 | ) | (a) | (2 | ) | ||||
Purchases | 1 | (a) | 1 | ||||||
Settlements | (1 | ) | (a) | (1 | ) | ||||
Ending balance at June 30, 2013 | $ | 3 | $ | (a) | $ | 3 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) | |
Natural gas: | |||||||||
Beginning balance at January 1, 2013 | $ | — | $ | — | $ | — | |||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | — | 1 | 1 | ||||||
Total realized and unrealized gains (losses) | — | 1 | 1 | ||||||
Purchases | (1 | ) | 1 | — | |||||
Ending balance at June 30, 2013 | $ | (1 | ) | $ | 2 | $ | 1 | ||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | — | $ | — | $ | — | |||
Power: | |||||||||
Beginning balance at January 1, 2013 | $ | 11 | $ | (111 | ) | $ | (100 | ) | |
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | 6 | 15 | 21 | ||||||
Total realized and unrealized gains (losses) | 6 | 15 | 21 | ||||||
Purchases | 40 | — | 40 | ||||||
Settlements | (22 | ) | 16 | (6 | ) | ||||
Transfers into Level 3 | (2 | ) | — | (2 | ) | ||||
Transfers out of Level 3 | 4 | — | 4 | ||||||
Ending balance at June 30, 2013 | $ | 37 | $ | (80 | ) | $ | (43 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | — | $ | 15 | $ | 15 | |||
Uranium: | |||||||||
Beginning balance at January 1, 2013 | $ | (2 | ) | $ | (a) | $ | (2 | ) | |
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Total realized and unrealized gains (losses) | (2 | ) | (a) | (2 | ) | ||||
Settlements | 1 | (a) | 1 | ||||||
Ending balance at June 30, 2013 | $ | (3 | ) | $ | (a) | $ | (3 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) |
(a) | Not applicable. |
Net derivative commodity contracts | |||||||||
Six Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at January 1, 2012 | $ | 3 | $ | (a) | $ | 3 | |||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Total realized and unrealized gains (losses) | (2 | ) | (a) | (2 | ) | ||||
Purchases | 2 | (a) | 2 | ||||||
Sales | (1 | ) | (a) | (1 | ) | ||||
Settlements | (1 | ) | (a) | (1 | ) | ||||
Transfers into Level 3 | 2 | (a) | 2 | ||||||
Ending balance at June 30, 2012 | $ | 3 | $ | (a) | $ | 3 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012 | $ | (1 | ) | $ | (a) | $ | (1 | ) | |
Natural gas: | |||||||||
Beginning balance at January 1, 2012 | $ | (14 | ) | $ | (160 | ) | $ | (174 | ) |
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | (2 | ) | (26 | ) | (28 | ) | |||
Total realized and unrealized gains (losses) | (2 | ) | (26 | ) | (28 | ) | |||
Settlements | 1 | 16 | 17 | ||||||
Transfers out of Level 3 | 15 | 170 | 185 | ||||||
Ending balance at June 30, 2012 | $ | — | $ | — | $ | — | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012 | $ | 9 | $ | 114 | $ | 123 | |||
Power(b): | |||||||||
Beginning balance at January 1, 2012 | $ | 21 | $ | (140 | ) | $ | 81 | ||
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | 9 | (221 | ) | (168 | ) | ||||
Total realized and unrealized gains (losses) | 9 | (221 | ) | (168 | ) | ||||
Purchases | 22 | — | 22 | ||||||
Settlements | (24 | ) | 140 | (14 | ) | ||||
Transfers out of Level 3 | (2 | ) | — | (2 | ) | ||||
Ending balance at June 30, 2012 | $ | 26 | $ | (221 | ) | $ | (81 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012 | $ | 3 | $ | (195 | ) | (c) $ | (179 | ) | |
Uranium: | |||||||||
Beginning balance at January 1, 2012 | $ | (1 | ) | $ | (a) | $ | (1 | ) | |
Realized and unrealized gains (losses): | |||||||||
Included in regulatory assets/liabilities | — | (a) | — | ||||||
Total realized and unrealized gains (losses) | — | (a) | — | ||||||
Ending balance at June 30, 2012 | $ | (1 | ) | $ | (a) | $ | (1 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2012 | $ | — | $ | (a) | $ | — |
(a) | Not applicable. |
(b) | Ameren amounts include the elimination of financial power contracts between Ameren Illinois and Marketing Company. |
(c) | The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois’ swap contracts, which expire May 2032. |
Three Months | Six Months | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Ameren - derivative commodity contracts: | |||||||||||||||
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils | $ | — | $ | — | $ | — | $ | 2 | |||||||
Transfers out of Level 3 / Transfers into Level 2 - Natural gas | — | — | — | 185 | |||||||||||
Transfers into Level 3 / Transfers out of Level 2 - Power | — | — | (2 | ) | — | ||||||||||
Transfers out of Level 3 / Transfers into Level 2 - Power | 3 | (1 | ) | 4 | (2 | ) | |||||||||
Net fair value of Level 3 transfers | $ | 3 | $ | (1 | ) | $ | 2 | $ | 185 | ||||||
Ameren Missouri - derivative commodity contracts: | |||||||||||||||
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils | $ | — | $ | — | $ | — | $ | 2 | |||||||
Transfers out of Level 3 / Transfers into Level 2 - Natural gas | — | — | — | 15 | |||||||||||
Transfers into Level 3 / Transfers out of Level 2 - Power | — | — | (2 | ) | — | ||||||||||
Transfers out of Level 3 / Transfers into Level 2 - Power | 3 | (1 | ) | 4 | (2 | ) | |||||||||
Net fair value of Level 3 transfers | $ | 3 | $ | (1 | ) | $ | 2 | $ | 15 | ||||||
Ameren Illinois - derivative commodity contracts: | |||||||||||||||
Transfers out of Level 3 / Transfers into Level 2 - Natural gas | $ | — | $ | — | $ | — | $ | 170 |
June 30, 2013 | December 31, 2012 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Ameren:(a)(b) | |||||||||||||||
Long-term debt and capital lease obligations (including current portion) | $ | 6,158 | $ | 6,864 | $ | 6,157 | $ | 7,110 | |||||||
Preferred stock | 142 | 124 | 142 | 123 | |||||||||||
Ameren Missouri: | |||||||||||||||
Long-term debt and capital lease obligations (including current portion) | $ | 4,006 | $ | 4,470 | $ | 4,006 | $ | 4,625 | |||||||
Preferred stock | 80 | 75 | 80 | 73 | |||||||||||
Ameren Illinois: | |||||||||||||||
Long-term debt (including current portion) | $ | 1,727 | $ | 1,940 | $ | 1,727 | $ | 2,020 | |||||||
Preferred stock | 62 | 49 | 62 | 49 |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
(b) | Preferred stock along with the noncontrolling interest of EEI is recorded in “Noncontrolling Interests” on the balance sheet. |
• | $166 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. As of June 30, 2013, this amount does not represent an incremental consolidated Ameren obligation; rather, it represents Ameren parental guarantees of subsidiary obligations to third parties, which may include affiliates, in order to allow the subsidiaries the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Ameren's estimated exposure for obligations under transactions covered by these guarantees was $29 million at June 30, 2013, which represents the total amount Ameren (parent) could be required to fund based on June 30, 2013 market prices. |
• | $33 million associated with the guarantee provided by Ameren for Medina Valley on March 14, 2013, relating to the amended put option agreement between Genco and Medina Valley. Genco exercised the put option in March 2013 and received an initial payment of $100 million. Genco advanced the initial payment amount it received into the non-state-regulated subsidiary money pool. |
• | $25 million provided to a clearing broker acting as futures commission merchant for the clearing of certain power, natural gas, and fuels commodity transactions for AER. |
• | $6 million related to requirements for asset transactions, leasing, Medina Valley transactions through MISO and other |
Three Months | Six Months | |||||||||||||
Agreement | Income Statement Line Item | Ameren Missouri | Ameren Illinois | Ameren Missouri | Ameren Illinois | |||||||||
Ameren Missouri power supply | Operating Revenues | 2013 | $ | (b) | $ | (a) | $ | 1 | $ | (a) | ||||
agreements with Ameren Illinois | 2012 | (b) | (a) | (b) | (a) | |||||||||
Ameren Missouri and Ameren Illinois | Operating Revenues | 2013 | 5 | (b) | 11 | (b) | ||||||||
rent and facility services | 2012 | 5 | (b) | 9 | (b) | |||||||||
Ameren Missouri and Genco gas | Operating Revenues | 2013 | (b) | (a) | (b) | (a) | ||||||||
transportation agreement | 2012 | (b) | (a) | (b) | (a) | |||||||||
Transmission services agreement | Operating Revenues | 2013 | (a) | 7 | (a) | 13 | ||||||||
with Marketing Company | 2012 | (a) | 3 | (a) | 5 | |||||||||
Total Operating Revenues | 2013 | $ | 5 | $ | 7 | $ | 12 | $ | 13 | |||||
2012 | 5 | 3 | 9 | 5 | ||||||||||
Ameren Illinois power supply | Purchased Power | 2013 | $ | (a) | $ | 22 | $ | (a) | $ | 48 | ||||
agreements with Marketing Company | 2012 | (a) | 72 | (a) | 160 | |||||||||
Ameren Illinois power supply | Purchased Power | 2013 | (a) | (b) | (a) | 1 | ||||||||
agreements with Ameren Missouri | 2012 | (a) | (b) | (a) | (b) | |||||||||
Total Purchased Power | 2013 | $ | (a) | $ | 22 | $ | (a) | $ | 49 | |||||
2012 | (a) | 72 | (a) | 160 | ||||||||||
Ameren Services support services | Other Operations and Maintenance | 2013 | $ | 28 | $ | 24 | $ | 60 | $ | 48 | ||||
agreement | 2012 | 27 | 22 | 55 | 45 | |||||||||
Insurance premiums(c) | Other Operations and Maintenance | 2013 | (b) | (a) | (b) | (a) | ||||||||
2012 | (b) | (a) | (b) | (a) | ||||||||||
Total Other Operations and | 2013 | $ | 28 | $ | 24 | $ | 60 | $ | 48 | |||||
Maintenance Expenses | 2012 | 27 | 22 | 55 | 45 | |||||||||
Money pool borrowings (advances) | Interest Charges | 2013 | $ | __ | $ | (b) | $ | (b) | $ | (b) | ||||
2012 | __ | (b) | __ | (b) |
(a) | Not applicable. |
(b) | Amount less than $1 million. |
(c) | Represents insurance premiums paid to Missouri Energy Risk Assurance Company, an affiliate, for replacement power. |
Type and Source of Coverage | Maximum Coverages | Maximum Assessments for Single Incidents | ||||||
Public liability and nuclear worker liability: | ||||||||
American Nuclear Insurers | $ | 375 | $ | — | ||||
Pool participation | 12,219 | (a) | 118 | (b) | ||||
$ | 12,594 | (c) | $ | 118 | ||||
Property damage: | ||||||||
Nuclear Electric Insurance Ltd. | $ | 2,750 | (d) | $ | 23 | (e) | ||
Replacement power: | ||||||||
Nuclear Electric Insurance Ltd. | $ | 490 | (f) | $ | 9 | (e) | ||
Missouri Energy Risk Assurance Company | $ | 64 | (g) | $ | — |
(a) | Provided through mandatory participation in an industry-wide retrospective premium assessment program. |
(b) | Retrospective premium under Price-Anderson. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $17.5 million per year. |
(c) | Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors. |
(d) | First layer of coverage provides for $500 million in property damage, decontamination, premature decommissioning, and the second layer of coverage provides excess property insurance up to $2.25 billion for losses in excess of the $500 million primary coverage. Effective April 1, 2013, a $1.5 billion sub-limit was established for non-radiation events. Effective July 1, 2013, an additional non-radiation limit of $200 million in excess of the $1.5 billion was made available. This additional coverage is a shared limit with other generators purchasing this coverage and includes one free reinstatement. Effective August 1, 2013, $500 million in excess of the $2.25 billion property coverage and $1.7 billion non-radiation coverage was provided by European Mutual Association for Nuclear Insurance. Concurrently, the Nuclear Electric Insurance Ltd. property limit for nuclear events was reduced by $500 million. |
(e) | All Nuclear Electric Insurance Ltd. insured plants could be subject to assessments should losses exceed the accumulated funds from Nuclear Electric Insurance Ltd. |
(f) | Provides replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Effective April 1, 2013, non-radiation events are sub-limited to $327.6 million. |
(g) | Provides replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 9 - Related Party Transactions for more information on this affiliate transaction. |
• | Ameren’s divestiture of its Merchant Generation business; |
• | additional or modified federal or state requirements; |
• | further regulation of greenhouse gas emissions; |
• | revisions to CAIR or reinstatement of CSAPR; |
• | new national ambient air quality standards, new standards intended to achieve national ambient air quality standards, or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions; |
• | additional or new rules governing air pollutant transport; |
• | regulations under the Clean Water Act regarding cooling water intake structures or effluent standards; |
• | finalized regulations classifying CCR as being hazardous or imposing additional requirements on the management of CCR; |
• | new limitations or standards under the Clean Water Act applicable to discharges from steam-electric generating units; |
• | new technology; |
• | changes in expected power prices; |
• | variations in costs of material or labor; and |
• | alternative compliance strategies or investment decisions. |
2013 | 2014 - 2017 | 2018 - 2022 | Total | ||||||||||||||||||||||||
AMO(a) | $ | 105 | $ | 215 | - | $ | 260 | $ | 795 | - | $ | 975 | $ | 1,115 | - | $ | 1,340 |
(a) | Ameren Missouri’s expenditures are expected to be recoverable from ratepayers. |
2013 | 2014 - 2017 | 2018 - 2022 | Total | ||||||||||||||||||||||||
Genco(a) | $ | 30 | $ | 100 | - | $ | 125 | $ | 220 | - | $ | 270 | $ | 350 | - | $ | 425 | ||||||||||
AERG | 5 | 20 | - | 25 | 20 | - | 25 | 45 | - | 55 | |||||||||||||||||
Total(b) | $ | 35 | $ | 120 | - | $ | 150 | $ | 240 | - | $ | 295 | $ | 395 | - | $ | 480 |
(a) | Includes estimated costs of approximately $20 million annually, excluding capitalized interest, from 2013 through 2017 for construction of two scrubbers at the Newton energy center. |
(b) | Assumes the Merchant Generation facilities are owned by Ameren. |
• | A schedule of milestones for completion of various aspects of the installation and completion of the scrubber projects at Genco's Newton energy center; the first milestone relates to the completion of engineering design by July 2015 while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019. |
• | A requirement for AER to refrain from operating the Meredosia and Hutsonville energy centers through December 31, 2020; however, this restriction does not impact Genco's ability, or Ameren’s ability after the divestiture of New AER occurs, to make the Meredosia energy center available for any parties that may be interested in repowering one of its units to create an oxy-fuel combustion coal-fired energy center designed for permanent carbon dioxide capture and storage. |
Estimate | Recorded Liability(a) | ||||||||||
Low | High | ||||||||||
Ameren | $ | 256 | $ | 339 | $ | 256 | |||||
Ameren Missouri | 5 | 6 | 5 | ||||||||
Ameren Illinois | 251 | 333 | 251 |
(a) | Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was a better estimate. |
Ameren | Ameren Missouri | Ameren Illinois | Total(a) | |||
2 | 58 | 68 | 90 |
(a) | Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants. |
Pension Benefits (a) | Postretirement Benefits (a) | ||||||||||||||||||||||||||||||
Three Months | Six Months | Three Months | Six Months | ||||||||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||
Service cost | $ | 22 | $ | 20 | $ | 46 | $ | 41 | $ | 5 | $ | 5 | $ | 11 | $ | 11 | |||||||||||||||
Interest cost | 41 | 41 | 81 | 83 | 11 | 11 | 23 | 24 | |||||||||||||||||||||||
Expected return on plan assets | (54 | ) | (52 | ) | (108 | ) | (104 | ) | (15 | ) | (14 | ) | (31 | ) | (28 | ) | |||||||||||||||
Amortization of: | |||||||||||||||||||||||||||||||
Prior service cost (benefit) | (1 | ) | (1 | ) | (2 | ) | (2 | ) | (1 | ) | (1 | ) | (2 | ) | (2 | ) | |||||||||||||||
Actuarial loss | 24 | 18 | 46 | 37 | 2 | (1 | ) | 4 | 2 | ||||||||||||||||||||||
Net periodic benefit cost | $ | 32 | $ | 26 | $ | 63 | $ | 55 | $ | 2 | $ | — | $ | 5 | $ | 7 |
(a) | Excludes the EEI plans as they are included in discontinued operations. |
Pension Costs | Postretirement Costs | ||||||||||||||||||||||||||||||
Three Months | Six Months | Three Months | Six Months | ||||||||||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||||||||||
Ameren Missouri | $ | 18 | $ | 16 | $ | 36 | $ | 32 | $ | 2 | $ | — | $ | 5 | $ | 5 | |||||||||||||||
Ameren Illinois | 11 | 8 | 21 | 18 | (1 | ) | — | — | 2 | ||||||||||||||||||||||
Other | 3 | 2 | 6 | 5 | 1 | — | — | — | |||||||||||||||||||||||
Ameren(a) | $ | 32 | $ | 26 | $ | 63 | $ | 55 | $ | 2 | $ | — | $ | 5 | $ | 7 |
(a) | Includes amounts for Ameren registrants and nonregistrant subsidiaries, but excludes the EEI plans as they are included in discontinued operations. |
Three Months | Ameren Missouri | Ameren Illinois | Other | Intersegment Eliminations | Consolidated | |||||||||||||||
2013 | ||||||||||||||||||||
External revenues | $ | 883 | $ | 514 | $ | 6 | $ | — | $ | 1,403 | ||||||||||
Intersegment revenues | 6 | 2 | — | (8 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 84 | 31 | (10 | ) | — | 105 | ||||||||||||||
2012 | ||||||||||||||||||||
External revenues | $ | 838 | $ | 564 | $ | — | $ | — | $ | 1,402 | ||||||||||
Intersegment revenues | 6 | — | 1 | (7 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 143 | 32 | (14 | ) | — | 161 | ||||||||||||||
Six Months | ||||||||||||||||||||
2013 | ||||||||||||||||||||
External revenues | $ | 1,672 | $ | 1,197 | $ | 9 | $ | — | $ | 2,878 | ||||||||||
Intersegment revenues | 13 | 3 | 1 | (17 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 124 | 62 | (27 | ) | — | 159 | ||||||||||||||
2012 | ||||||||||||||||||||
External revenues | $ | 1,524 | $ | 1,288 | $ | 2 | $ | — | $ | 2,814 | ||||||||||
Intersegment revenues | 11 | — | 2 | (13 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 164 | 59 | (25 | ) | — | 198 | ||||||||||||||
As of June 30, 2013: | ||||||||||||||||||||
Total assets | $ | 13,131 | $ | 7,366 | $ | 1,354 | $ | (1,061 | ) | $ | 20,790 | (a) | ||||||||
As of December 31, 2012: | ||||||||||||||||||||
Total assets | $ | 13,043 | $ | 7,282 | $ | 1,228 | $ | (944 | ) | $ | 20,609 | (a) |
• | 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 operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. |
• | AER consists of non-rate-regulated operations, including Genco, AERG, and Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes. |
• | costs associated with the Callaway energy center's scheduled refueling and maintenance outage in the second quarter of 2013. There was no Callaway refueling and maintenance outage in 2012 (8 cents per share and 9 cents per share, respectively); |
• | the absence in 2013 of a reduction in Ameren Missouri's purchased power expense that did not flow through the FAC and an increase in interest income, as occurred in the prior year. In June 2012, a FERC-ordered refund was received from Entergy for a power purchase agreement that expired in 2009 (7 cents per share in both periods); and |
• | a reduction in revenues at Ameren Missouri resulting from the FAC prudence review charge for the estimated obligation to refund to customers amounts associated with sales recognized for the period from October 1, 2009, to May 31, 2011 (6 cents per share in both periods). |
• | higher utility rates at Ameren Missouri pursuant to an order issued by the MoPSC, which became effective in January 2013, partially offset by increased regulatory asset amortization directed by the rate order (6 cents per share and 8 cents per share, respectively); |
• | higher electric transmission rates at Ameren Illinois and ATXI (2 cents per share and 5 cents per share, respectively); and |
• | higher revenues associated with Ameren Missouri's MEEIA energy efficiency lost revenue recovery mechanism (2 cents per share in both periods). |
Ameren Missouri | Ameren Illinois | Other / Intersegment Eliminations | Total | ||||||||||||
Three Months 2013: | |||||||||||||||
Electric margin | $ | 606 | $ | 288 | $ | — | $ | 894 | |||||||
Natural gas margin | 18 | 85 | — | 103 | |||||||||||
Other revenues | — | 2 | (2 | ) | — | ||||||||||
Other operations and maintenance | (253 | ) | (196 | ) | 2 | (447 | ) | ||||||||
Depreciation and amortization | (113 | ) | (62 | ) | (3 | ) | (178 | ) | |||||||
Taxes other than income taxes | (79 | ) | (30 | ) | (2 | ) | (111 | ) | |||||||
Other income and (expenses) | 11 | 1 | (1 | ) | 11 | ||||||||||
Interest charges | (56 | ) | (34 | ) | (10 | ) | (100 | ) | |||||||
Income (taxes) benefit | (49 | ) | (22 | ) | 5 | (66 | ) | ||||||||
Income (loss) from continuing operations | 85 | 32 | (11 | ) | 106 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (10 | ) | (10 | ) | |||||||||
Net income (loss) | 85 | 32 | (21 | ) | 96 | ||||||||||
Noncontrolling interest and preferred dividends | (1 | ) | (1 | ) | 1 | (1 | ) | ||||||||
Net income (loss) attributable to Ameren Corporation | $ | 84 | $ | 31 | $ | (20 | ) | $ | 95 | ||||||
Three Months 2012: | |||||||||||||||
Electric margin | $ | 645 | $ | 275 | $ | (1 | ) | $ | 919 | ||||||
Natural gas margin | 16 | 83 | (1 | ) | 98 | ||||||||||
Other revenues | 1 | — | (1 | ) | — | ||||||||||
Other operations and maintenance | (206 | ) | (186 | ) | (3 | ) | (395 | ) | |||||||
Depreciation and amortization | (109 | ) | (55 | ) | (4 | ) | (168 | ) | |||||||
Taxes other than income taxes | (78 | ) | (31 | ) | (1 | ) | (110 | ) | |||||||
Other income and (expenses) | 14 | — | (2 | ) | 12 | ||||||||||
Interest charges | (56 | ) | (31 | ) | (11 | ) | (98 | ) | |||||||
Income (taxes) benefit | (83 | ) | (22 | ) | 9 | (96 | ) | ||||||||
Income (loss) from continuing operations | 144 | 33 | (15 | ) | 162 | ||||||||||
Income from discontinued operations, net of tax | — | — | 48 | 48 | |||||||||||
Net income | 144 | 33 | 33 | 210 | |||||||||||
Noncontrolling interest and preferred dividends | (1 | ) | (1 | ) | 3 | 1 | |||||||||
Net income attributable to Ameren Corporation | $ | 143 | $ | 32 | $ | 36 | $ | 211 | |||||||
Six Months 2013: | |||||||||||||||
Electric margin | $ | 1,099 | $ | 521 | $ | (2 | ) | $ | 1,618 | ||||||
Natural gas margin | 45 | 216 | (1 | ) | 260 | ||||||||||
Other revenues | — | 2 | (2 | ) | — | ||||||||||
Other operations and maintenance | (474 | ) | (372 | ) | — | (846 | ) | ||||||||
Depreciation and amortization | (224 | ) | (123 | ) | (6 | ) | (353 | ) | |||||||
Taxes other than income taxes | (156 | ) | (72 | ) | (5 | ) | (233 | ) | |||||||
Other income and (expenses) | 20 | (1 | ) | (1 | ) | 18 | |||||||||
Interest charges | (116 | ) | (65 | ) | (20 | ) | (201 | ) | |||||||
Income (taxes) benefit | (68 | ) | (42 | ) | 9 | (101 | ) | ||||||||
Income (loss) from continuing operations | 126 | 64 | (28 | ) | 162 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (209 | ) | (209 | ) | |||||||||
Net income (loss) | 126 | 64 | (237 | ) | (47 | ) | |||||||||
Noncontrolling interest and preferred dividends | (2 | ) | (2 | ) | 1 | (3 | ) | ||||||||
Net income (loss) attributable to Ameren Corporation | $ | 124 | $ | 62 | $ | (236 | ) | $ | (50 | ) | |||||
Six Months 2012: | |||||||||||||||
Electric margin | $ | 1,081 | $ | 516 | $ | (4 | ) | $ | 1,593 | ||||||
Natural gas margin | 39 | 193 | (1 | ) | 231 | ||||||||||
Other revenues | 1 | — | (1 | ) | — | ||||||||||
Other operations and maintenance | (408 | ) | (354 | ) | (2 | ) | (764 | ) | |||||||
Depreciation and amortization | (217 | ) | (110 | ) | (8 | ) | (335 | ) | |||||||
Taxes other than income taxes | (149 | ) | (70 | ) | (4 | ) | (223 | ) | |||||||
Other income and (expenses) | 26 | (10 | ) | (2 | ) | 14 | |||||||||
Interest charges | (112 | ) | (64 | ) | (20 | ) | (196 | ) | |||||||
Income (taxes) benefit | (95 | ) | (40 | ) | 16 | (119 | ) | ||||||||
Income (loss) from continuing operations | 166 | 61 | (26 | ) | 201 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (394 | ) | (394 | ) | |||||||||
Net income (loss) | 166 | 61 | (420 | ) | (193 | ) | |||||||||
Noncontrolling interest and preferred dividends | (2 | ) | (2 | ) | 5 | 1 | |||||||||
Net income (loss) attributable to Ameren Corporation | $ | 164 | $ | 59 | $ | (415 | ) | $ | (192 | ) |
Three Months | Ameren Missouri | Ameren Illinois | Other(a) | Ameren | |||||||||||
Electric revenue change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | (25 | ) | $ | (4 | ) | $ | — | $ | (29 | ) | ||||
Regulated rates: | |||||||||||||||
Base rates (estimate) | 48 | 12 | — | 60 | |||||||||||
Recovery of FAC under-recovery(c) | 16 | — | — | 16 | |||||||||||
Off-system and transmission services revenues (reduction in base rates) | 26 | — | — | 26 | |||||||||||
FAC prudence review charge | (22 | ) | — | — | (22 | ) | |||||||||
MEEIA (energy efficiency) | 15 | — | — | 15 | |||||||||||
Transmission services | (7 | ) | 7 | 5 | 5 | ||||||||||
Bad debt, energy efficiency programs and environmental remediation cost riders | — | (5 | ) | — | (5 | ) | |||||||||
Illinois pass-through power supply costs | — | (82 | ) | — | (82 | ) | |||||||||
Sales volume (excluding the impact of abnormal weather) | (14 | ) | 3 | — | (11 | ) | |||||||||
Other | 1 | — | (1 | ) | — | ||||||||||
Total electric revenue change | $ | 38 | $ | (69 | ) | $ | 4 | $ | (27 | ) | |||||
Fuel and purchased power change: | |||||||||||||||
Energy costs included in base rates | $ | (37 | ) | $ | — | $ | — | $ | (37 | ) | |||||
Recovery of FAC under-recovery(c) | (16 | ) | — | — | (16 | ) | |||||||||
FERC-ordered power purchase settlement in 2012 | (24 | ) | — | — | (24 | ) | |||||||||
Illinois pass-through power supply costs and other | — | 82 | (3 | ) | 79 | ||||||||||
Total fuel and purchased power change | $ | (77 | ) | $ | 82 | $ | (3 | ) | $ | 2 | |||||
Net change in electric margins | $ | (39 | ) | $ | 13 | $ | 1 | $ | (25 | ) | |||||
Natural gas margins change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | 1 | $ | 3 | $ | — | $ | 4 | |||||||
Gross receipts tax | — | 1 | — | 1 | |||||||||||
Sales (excluding the impact of abnormal weather) and other | 1 | (2 | ) | 1 | — | ||||||||||
Net change in natural gas margins | $ | 2 | $ | 2 | $ | 1 | $ | 5 | |||||||
Six Months | Ameren Missouri | Ameren Illinois | Other(a) | Ameren | |||||||||||
Electric revenue change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | 6 | $ | 1 | $ | — | $ | 7 | |||||||
Regulated rates: | |||||||||||||||
Base rates (estimate) | 83 | (4 | ) | — | 79 | ||||||||||
Recovery of FAC under-recovery(c) | 34 | — | — | 34 | |||||||||||
Off-system and transmission services revenues (reduction in base rates) | 16 | — | (1 | ) | 15 | ||||||||||
FAC prudence review charge | (22 | ) | — | — | (22 | ) | |||||||||
MEEIA (energy efficiency) | 22 | — | — | 22 | |||||||||||
Transmission services | (14 | ) | 16 | 6 | 8 | ||||||||||
Gross receipts tax | 6 | — | — | 6 | |||||||||||
Bad debt, energy efficiency programs and environmental remediation cost riders | — | (4 | ) | — | (4 | ) | |||||||||
Illinois pass-through power supply costs | — | (145 | ) | — | (145 | ) | |||||||||
Sales volume (excluding the impact of abnormal weather) | (1 | ) | (3 | ) | — | (4 | ) | ||||||||
Other | 4 | (1 | ) | (2 | ) | 1 | |||||||||
Total electric revenue change | $ | 134 | $ | (140 | ) | $ | 3 | $ | (3 | ) | |||||
Fuel and purchased power change: | |||||||||||||||
Energy costs included in base rates | $ | (58 | ) | $ | — | $ | — | $ | (58 | ) |
Recovery of FAC under-recovery(c) | (34 | ) | — | — | (34 | ) | |||||||||
FERC-ordered power purchase settlement in 2012 | (24 | ) | — | — | (24 | ) | |||||||||
Illinois pass-through power supply costs and other | — | 145 | (1 | ) | 144 | ||||||||||
Total fuel and purchased power change | $ | (116 | ) | $ | 145 | $ | (1 | ) | $ | 28 | |||||
Net change in electric margins | $ | 18 | $ | 5 | $ | 2 | $ | 25 | |||||||
Natural gas margins change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | 3 | $ | 11 | $ | — | $ | 14 | |||||||
Base rates (estimate) | — | 2 | — | 2 | |||||||||||
Energy efficiency programs and environmental remediation cost riders | — | 5 | — | 5 | |||||||||||
Gross receipts tax | 1 | 5 | — | 6 | |||||||||||
Sales (excluding the impact of abnormal weather) and other | 2 | — | — | 2 | |||||||||||
Net change in natural gas margins | $ | 6 | $ | 23 | $ | — | $ | 29 |
(a) | Includes amounts for nonregistrant subsidiaries and intercompany eliminations. |
(b) | Represents the estimated margin impact resulting from the effects of changes in cooling and heating degree-days on electric and natural gas demand compared with the prior-year period based on temperature readings from the National Oceanic and Atmospheric Administration weather stations at local airports in our service territories. |
(c) | Represents the change in the net fuel costs recovered under the FAC through customer rates, with corresponding offsets to fuel expense due to amortization of a previously recorded regulatory asset. |
• | Higher electric base rates at Ameren Missouri, effective January 2013 ($48 million and $83 million, respectively), offset by an increase in net energy costs ($11 million and $42 million, respectively), approved in the 2012 MoPSC electric rate order. The increase in net energy costs are the sum of the change in energy costs included in base rates ($37 million and $58 million, respectively) and the change in off-system and transmission services revenues ($26 million and $16 million, respectively). Transmission services revenues for 2012 were not included in the FAC ($7 million and $14 million, respectively). See below for additional details regarding the FAC. |
• | Excluding Ameren Missouri, higher transmission revenues at Ameren Illinois and ATXI, due to the forward-looking rate calculations for 2013 pursuant to the 2012 FERC orders, whereas in 2012 rates were based on a historic base period ($12 million and $22 million, respectively). On January 1, 2013, Ameren Illinois and ATXI adjusted their electric transmission rates to reflect an increase in their transmission revenue requirements. The increases in Ameren Illinois' and ATXI’s transmission revenue requirements are subject to revenue requirement reconciliations. |
• | Higher revenues associated with Ameren Missouri's MEEIA energy efficiency program cost recovery mechanism ($8 million and $13 million, respectively) and lost revenue recovery mechanism ($7 million and $9 million, respectively), effective January 2013, which increased revenues by a combined $15 million and $22 million, respectively. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs. |
• | Electric delivery service formula ratemaking adjustments at Ameren Illinois resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA increased revenues by $12 million for the three months ended June 30, 2013, when compared with the same period in 2012. The increase in revenues in 2013 was primarily a result of the variation in the timing and amount of expected full-year recoverable costs under formula ratemaking. |
• | Winter weather conditions in 2013 were normal compared to warmer-than-normal conditions for the same period in 2012, with a 45% increase in heating degree-days, which increased revenues by $7 million for the six months ended June 30, 2013, compared with the same period in 2012. |
• | Increased gross receipts tax collections at Ameren Missouri, due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $6 million for the six months ended June 30, 2013, compared with the same period in 2012. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes. |
• | Weather conditions in the second quarter of 2013 were mild compared to warmer-than-normal conditions for the same period in 2012, as evidenced by a 24% decrease in cooling degree-days, which decreased revenues by $29 million, for the three months ended June 30, 2013, compared with the same period in 2012. |
• | Absence in 2013 of a reduction to Ameren Missouri’s purchased power expense that did not flow through the FAC as a result of a FERC-ordered refund from Entergy received in 2012 related to a power purchase agreement that expired in 2009 ($24 million for both periods). |
• | A reduction in revenues at Ameren Missouri resulting from the Missouri Court of Appeal's May 2013 decision that upheld the MoPSC's April 2011 order. Ameren Missouri recorded a FAC prudence review charge for its estimated obligation to refund to its electric customers the earnings |
• | Excluding the estimated impact of abnormal weather, total sales volumes were comparable for the three and six months ended June 30, 2013, respectively, compared with the same periods in 2012; however, revenues decreased $11 million and $4 million, respectively, due in part to decreased sales in the commercial sector at Ameren Missouri. |
• | Electric delivery service formula ratemaking adjustments at Ameren Illinois resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA decreased revenues by $4 million for the six months ended June 30, 2013, when compared with the same period in 2012. The decrease in revenues in 2013 was primarily a result of variation in the timing and amount of expected full-year recoverable costs under formula ratemaking. |
• | A decrease in recovery of bad debt, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms at Ameren Illinois ($5 million and $4 million, respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting decrease in energy efficiency and environmental remediation costs. |
• | Weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, with an increase in heating degree-days of 74% and 45%, respectively ($4 million and $14 million, respectively). |
• | Increased gross receipts tax collections, primarily at Ameren Illinois, due to higher sales as a result of colder winter weather in 2013 compared with 2012 ($1 million and $6 million, respectively). See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes. |
• | An increase in recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms at Ameren Illinois increased revenues by $5 million for the six months ended June 30, 2013, when compared with the same period in 2012. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs. |
• | Excluding the estimated impact of abnormal weather, total retail sales volumes were comparable for the six months ended June 30, 2013, when compared with the same period last year; however, revenues increased by $2 million, driven largely by higher natural gas transportation sales at Ameren Missouri. |
• | Increased natural gas rates effective in late January 2012, at Ameren Illinois, increased revenues by $2 million, for the six months ended June 30, 2013, when compared with the same period in 2012. |
• | Higher electric base rates, effective January 2013 ($48 million and $83 million, respectively), as a result of the 2012 MoPSC electric rate order, offset by an increase in net energy costs ($11 million and $42 million, respectively). The increase in net energy costs are the sum of the change in energy costs included in base rates ($37 million and $58 million, respectively) and the change in off-system and transmission services revenues ($26 million and $16 million, respectively). Transmission services revenues for 2012 were not included in the FAC ($7 million and $14 million, respectively). |
• | Higher revenues associated with the MEEIA energy efficiency program cost recovery mechanism ($8 million and $13 million, respectively) and the lost revenue recovery mechanism ($7 million and $9 million, respectively), effective January 2013, which increased revenues by a combined $15 million and $22 million, respectively. See Other |
• | Winter weather conditions in 2013 were normal compared to warmer-than-normal conditions for the same period in 2012, with a 51% increase in heating degree-days, which increased revenues by $6 million for the six months ended June 30, 2013, compared with the same period in 2012. |
• | Increased gross receipts tax collections due to higher sales as a result of colder winter weather in 2013 compared with 2012, which, increased revenues by $6 million for the six months ended June 30, 2013, compared with the same period in 2012. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes. |
• | Weather conditions in the second quarter of 2013 were mild compared to warmer-than-normal conditions for the same period in 2012, as evidenced by a 26% decrease in cooling degree-days, which decreased revenues by $25 million, for the three months ended June 30, 2013, compared with the same period in 2012. |
• | Absence in 2013 of a reduction to purchased power expense that did not flow through the FAC as a result of a FERC-ordered refund from Entergy received in 2012 related to a power purchase agreement that expired in 2009 ($24 million for both periods). |
• | A reduction in revenues resulting from the Missouri Court of Appeal's May 2013 decision that upheld the MoPSC's April 2011 order. Ameren Missouri recorded a FAC prudence review charge for its estimated obligation to refund to its electric customers the earnings associated with sales previously recognized during the period from October 1, 2009, to May 31, 2011 ($22 million for both periods). See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information regarding the FAC prudence review charge. |
• | Excluding the estimated impact of abnormal weather, total retail sales volumes decreased 1%, due in part to decreased sales in the commercial sector, which decreased revenues by $14 million for the three months ended June 30, 2013, when compared with the same period last year. |
• | Weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, with an increase in heating degree-days of 100% and 51%, respectively ($1 million and $3 million, respectively). |
• | Excluding the estimated impact of abnormal weather, total retail sales volumes were comparable for the six months ended June 30, 2013, when compared with the same period last year; however, revenues increased by $2 million, driven largely by higher natural gas transportation sales. |
• | Increased gross receipts tax collection due to higher sales as a result of colder winter weather in 2013 compared with 2012, which increased revenues by $1 million for the six months ended June 30, 2013, when compared with the same period in 2012. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes. |
• | Higher transmission revenues due to the forward-looking rate calculation for 2013 pursuant to a 2012 FERC order, whereas in 2012 rates were based on a historic base period ($7 million and $16 million, respectively). On January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement, which is subject to revenue requirement reconciliation. |
• | Electric delivery service formula ratemaking adjustments resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA increased revenues by $12 million for the three months ended June 30, 2013, when compared with the same period in 2012. The increase in revenues in 2013 was primarily a result of variation in the timing and amount of expected full-year recoverable costs under formula ratemaking. |
• | Excluding the estimated impact of abnormal weather, total retail sales volumes increased 1%, primarily in the residential sector, where revenues increased by $3 million for the three months ended June 30, 2013, when compared with the same period in 2012. |
• | Winter weather conditions in 2013 were normal compared to warmer-than-normal conditions for the same period in 2012, with a 42% increase in heating degree-days, which increased revenues by $1 million for the six months ended June 30, 2013, compared with the same period in 2012. |
• | Weather conditions in the second quarter of 2013 were mild compared to warmer-than-normal conditions for the same period in 2012, as evidenced by a 23% decrease in cooling degree-days, which decreased revenues by $4 million for the three months ended June 30, 2013, compared with the same period in 2012. |
• | Electric delivery service formula ratemaking adjustments resulting from the annual reconciliation of the revenue requirement pursuant to the IEIMA decreased revenues by $4 million for the six months ended June 30, 2013, when compared with the same period in 2012. The decrease in revenues in 2013 was primarily a result of the variation in the timing and amount of expected full-year recoverable costs under formula ratemaking. |
• | A decrease in recovery of bad debt, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms ($5 million and $4 million, respectively). See Other Operations and Maintenance Expenses in this section for information on a related offsetting decrease in energy efficiency and environmental remediation costs. |
• | Excluding the estimated impact of abnormal weather, total retail sales volumes decreased 1% for the six months ended June 30, 2013, when compared with the same period in 2012, primarily in the industrial sector, which decreased revenues by $3 million. |
• | Weather conditions in 2013 were normal compared to warmer-than-normal conditions in 2012, with an increase in heating degree-days of 64% and 42%, respectively ($3 million and $11 million, respectively). |
• | An increase in recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $5 million for the six months ended June 30, 2013, when compared with the same period in 2012. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs. |
• | Increased gross receipts tax collections, due to higher sales as a result of colder winter weather in 2013 compared with 2012 ($1 million and $5 million, respectively). See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes. |
• | Increased natural gas rates effective in late January 2012, which increased revenues by $2 million for the six months ended June 30, 2013, when compared with the same period in 2012. |
• | A $25 million increase in plant maintenance costs, primarily due to $30 million in costs for the scheduled 2013 Callaway energy center refueling and maintenance outage, partially offset by a $5 million reduction in costs due to fewer major boiler outages at coal-fired energy centers. |
• | A $9 million increase in employee benefit costs, primarily due to higher pension expense because of increased amortization as a result of the 2012 MoPSC electric order for Ameren Missouri and actuarial adjustments for Ameren Illinois. For Ameren Missouri, the increased amortization expenses of $4 million were offset by increased electric revenues recovered through customer billings, with no overall impact on net income. |
• | An $8 million increase in Ameren Missouri’s energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013. These costs were offset by increased electric revenues recovered through customer billings, with no overall impact on net income. |
• | A $7 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. For Ameren Missouri, a portion of these costs were offset by increased electric revenues recovered through customer billings. For Ameren Illinois, these costs are recoverable under the provisions of the IEIMA. |
• | A $6 million increase in labor costs, primarily because of wage increases and Ameren Illinois staff additions to comply with the requirements of the IEIMA. |
• | A $3 million increase in Ameren Illinois natural gas operations and maintenance expenses, primarily because of pipeline integrity compliance. |
• | A $28 million increase in plant maintenance costs, primarily |
• | A $14 million increase in labor costs, primarily because of wage increases and Ameren Illinois staff additions to comply with the requirements of the IEIMA. |
• | A $13 million increase in Ameren Missouri’s energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013. |
• | A $9 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. |
• | A $6 million increase in Ameren Illinois natural gas operations and maintenance expenses, primarily because of pipeline integrity compliance. |
• | A $4 million increase in Ameren Illinois energy efficiency and environmental remediation costs. These costs were offset by increased electric and natural gas revenues recovered through customer billings, with no overall impact on net income. |
• | A $3 million increase in employee benefit costs, primarily due to higher pension expense at Ameren Missouri because of increased amortization as a result of the 2012 MoPSC electric order. |
• | A $25 million increase in plant maintenance costs, primarily due to $30 million in costs for the scheduled 2013 Callaway energy center refueling and maintenance outage, partially offset by a $5 million reduction in costs due to fewer major boiler outages at coal-fired energy centers. |
• | An $8 million increase in energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013. |
• | A $4 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. A portion of these costs, $2 million, were offset by increased electric revenues recovered through customer billings. |
• | A $4 million increase in employee benefit costs, primarily due to higher pension expense because of increased amortization as a result of the 2012 MoPSC electric order. The increased amortization expenses were offset by increased electric revenues recovered through customer billings, with no overall impact on net income. |
• | A $28 million increase in plant maintenance costs, primarily due to $36 million in costs for the scheduled 2013 Callaway energy center refueling and maintenance outage, partially offset by an $8 million reduction in costs due to fewer major boiler outages at coal-fired energy centers. |
• | A $13 million increase in energy efficiency program costs due to the requirements of MEEIA, which became effective in rates beginning in January 2013. |
• | A $7 million increase in storm-related repair costs, primarily due to major storms in the second quarter of 2013. A portion of these costs, $3 million, were offset by increased electric revenues recovered through customer billings. |
• | A $5 million increase in employee benefit costs, primarily due to higher pension expense because of increased amortization as a result of the 2012 MoPSC electric order. |
• | A $4 million increase in labor costs, primarily because of wage increases. |
• | A $5 million increase in labor costs, primarily because of wage increases and staff additions to comply with the requirements of the IEIMA. |
• | A $3 million increase in natural gas operations and maintenance expenses, primarily because of pipeline integrity compliance. |
• | A $3 million increase in storm-related repair costs, primarily due to major storms in 2013. |
• | A $2 million increase in employee benefit costs, primarily due to higher pension expense resulting from actuarial adjustments. |
• | A $7 million increase in labor costs, primarily because of wage increases and staff additions to comply with the requirements of the IEIMA. |
• | A $6 million increase in natural gas operations and |
• | A $4 million increase in energy efficiency and environmental remediation costs. These costs were offset by increased electric and natural gas revenues recovered through customer billings, with no overall impact on net income. |
• | A $2 million increase in storm-related repair costs, primarily due to major storms in 2013. |
Three Months | Six Months | ||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||
Ameren(a) | 38 | % | 37 | % | 38 | % | 37 | % | |||
Ameren Missouri(a) | 37 | % | 37 | % | 35 | % | 36 | % | |||
Ameren Illinois(a) | 41 | % | 40 | % | 40 | % | 40 | % |
(a) | The provision for income taxes was based on the current estimate of the annual effective tax rate adjusted to reflect the tax impact of items discrete to the relevant period. |
Net Cash Provided By Operating Activities | Net Cash (Used In) Investing Activities | Net Cash (Used In) Financing Activities | |||||||||||||||||||||||||||||||||
2013 | 2012 | Variance | 2013 | 2012 | Variance | 2013 | 2012 | Variance | |||||||||||||||||||||||||||
Ameren(a) - continuing operations | $ | 729 | $ | 664 | $ | 65 | $ | (606 | ) | $ | (549 | ) | $ | (57 | ) | $ | (165 | ) | $ | (305 | ) | $ | 140 | ||||||||||||
Ameren(a) - discontinued operations | 39 | 97 | (58 | ) | (31 | ) | (64 | ) | 33 | — | — | — | |||||||||||||||||||||||
Ameren Missouri | 338 | 301 | 37 | (285 | ) | (367 | ) | 82 | (182 | ) | (135 | ) | (47 | ) | |||||||||||||||||||||
Ameren Illinois | 426 | 360 | 66 | (279 | ) | (247 | ) | (32 | ) | (49 | ) | (74 | ) | 25 |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
• | A $57 million increase due to changes in coal inventory levels. During 2013, coal inventory levels were $36 million lower than year end because of delivery disruptions due to flooding, while in the 2012 comparable period, coal inventory levels increased $21 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions and warmer-than-normal weather conditions. |
• | Electric and natural gas margins, as discussed in Results of Operations, increased by $55 million, excluding impacts from the noncash IEIMA revenue requirement reconciliation accrual and May 2013 court order FAC prudence review charge. See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information. |
• | A $47 million increase due to the cash flows associated with Ameren Missouri’s under-recovered FAC costs. Recoveries outpaced deferrals in 2013 by $31 million, while deferrals and refunds outpaced recoveries in 2012 by $16 million. |
• | A net $36 million decrease in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity |
• | A $28 million increase in natural gas commodity over-recovered costs under the PGA, primarily related to Ameren Illinois. |
• | The absence of $25 million in severance payments made in 2012 as a result of the voluntary separation offers extended to Ameren Missouri employees in the fourth quarter of 2011. |
• | A $12 million decrease in natural gas held in storage due to a cooler than normal spring in 2013 resulting in larger withdrawals, partially offset by higher natural gas prices. |
• | A $10 million decrease in pension and postretirement benefit plan contributions caused by the timing of payments in 2013 compared with 2012. |
• | A $10 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments made on Ameren Missouri and Ameren Illinois senior secured notes in 2013 compared to 2012. |
• | A $7 million decrease in payments to MISO for purchased power as more Ameren Illinois customers switched to an alternative retail electric supplier as their power provider. |
• | Income tax payments of $60 million in 2013, compared with income tax refunds of $3 million in 2012. As discussed below, income tax payments at Ameren Missouri decreased $8 million while income tax refunds at Ameren Illinois decreased $26 million. Additionally, during 2012 Ameren received refunds resulting from an income tax credit investment, which did not result in the receipt of refunds |
• | A $57 million increase in accounts receivable balances between the first six months of both years to reflect revenues earned, but not yet collected from customers. |
• | A $28 million increase in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center partially offset by unpaid liabilities as of December 31, 2011, pertaining to the fall 2011 outage, that were paid in 2012. There was no refueling and maintenance outage in 2012. |
• | A $20 million increase in property tax payments at Ameren Missouri caused by the timing of payments and higher assessed property tax values. |
• | The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $19 million from the Circuit Court of Stoddard County's registry, net of payments into that registry, as a result of a Missouri Court of Appeal ruling upholding the MoPSC's January 2009 electric rate order. |
• | An $18 million decrease at Ameren Illinois associated with deferred recoveries of electric purchased power commodity and transmission delivery pass-through costs. |
• | A $6 million increase in major storm restoration costs. |
• | A $57 million increase due to changes in coal inventory levels. During 2013, coal inventory levels were $36 million lower than year end because of delivery disruptions due to flooding, while in 2012, coal inventory levels increased $21 million primarily due to additional tons held in inventory because generation levels were below expected levels due to market conditions and warmer-than-normal weather conditions. |
• | A $47 million increase due to the cash flows associated with under-recovered FAC costs. Recoveries outpaced deferrals in 2013 by $31 million, while deferrals and refunds outpaced recoveries in 2012 by $16 million. |
• | Electric and natural gas margins, as discussed in Results of Operations, increased by $47 million, excluding the impact from the noncash charge recorded in the second quarter of 2013 as a result of the FAC prudence review charge in May 2013. See Note 3 - Rate and Regulatory Matters under Part I, Item 1, of this report for further information. |
• | The absence of $25 million in severance payments made in 2012 as a result of the voluntary separation offers extended to employees in the fourth quarter of 2011. |
• | A $62 million increase in accounts receivable balances between the first six months of both years to reflect revenues earned, but not yet collected from customers. |
• | A $28 million increase in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center partially offset by unpaid liabilities as of December 31, 2011, pertaining to the fall 2011 outage, that were paid in 2012. There was no refueling and maintenance outage in 2012. |
• | A $20 million increase in property tax payments caused by the timing of payments and higher assessed property tax values. |
• | The absence in 2013 of court registry receipts and payments. In 2012, Ameren Missouri received $19 million from the Circuit Court of Stoddard County's registry, net of payments into that registry, as a result of a Missouri Court of Appeal ruling upholding the MoPSC's January 2009 electric rate order. |
• | An $8 million increase in income tax payments resulting primarily from the timing in payment of income taxes in 2012 partially offset by a reduction in accelerated depreciation deductions. |
• | A $6 million increase in major storm restoration costs. |
• | A net $28 million decrease in collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes as well as 2013 credit rating upgrades. |
• | A $27 million decrease in pension and postretirement benefit plan contributions caused by the timing of payments in 2013 compared with 2012. |
• | A $22 million increase in natural gas commodity over-recovered costs under the PGA. |
• | A $10 million decrease in natural gas held in storage due to a cooler than normal spring in 2013 resulting in larger withdrawals, partially offset by higher natural gas prices. |
• | A $8 million decrease in interest payments, primarily due to 2012 refinancing activity and timing of payments on senior secured notes. |
• | A $7 million decrease in payments to MISO for purchased power as more Ameren Illinois customers switched to an alternative retail electric supplier as their power provider. |
• | Electric and natural gas margins, as discussed in Results of Operations, increased by $6 million, excluding the impact from the noncash IEIMA revenue requirement reconciliation adjustment. |
• | A $26 million decrease in income tax refunds resulting primarily from a reduction in accelerated depreciation deductions. |
• | An $18 million decrease associated with deferred recoveries of electric purchased power commodity and transmission delivery pass-through costs. |
Expiration | Borrowing Capacity | Credit Available | |||||||
Ameren and Ameren Missouri: | |||||||||
2012 Missouri Credit Agreement(a)(b) | November 2017 | $ | 1,000 | $ | 1,000 | ||||
Ameren and Ameren Illinois: | |||||||||
2012 Illinois Credit Agreement(a)(b) | November 2017 | 1,100 | 1,100 | ||||||
Ameren: | |||||||||
Less: | |||||||||
Commercial paper outstanding | (c) | (25 | ) | ||||||
Letters of credit | (c) | (14 | ) | ||||||
Total | $ | 2,100 | $ | 2,061 |
(a) | Certain Ameren subsidiaries not party to the 2012 Credit Agreements may access these credit agreements through intercompany borrowing arrangements. |
(b) | Each credit agreement expires on November 14, 2017. The borrowing sublimits of Ameren Missouri and Ameren Illinois will mature and expire on November 13, 2013, subject to extension on a 364-day basis or for a longer period upon notice by the respective borrower of receipt of any and all required federal or state regulatory approvals, as permitted under each credit agreement, but in no event later than November 14, 2017. Ameren Missouri and Ameren Illinois plan to seek or maintain any and all required federal or state regulatory approval necessary to extend the maturity date of their borrowing sublimits under the 2012 Credit Agreements to November 14, 2017. |
(c) | Not applicable. |
Six Months | |||||||
2013 | 2012 | ||||||
Ameren Missouri | $ | 180 | $ | 200 | |||
Ameren Illinois | 30 | 75 | |||||
Dividends paid by Ameren | 194 | 187 |
Moody’s | S&P | Fitch | ||||
Ameren: | ||||||
Issuer/corporate credit rating | Baa3 | BBB | BBB | |||
Senior unsecured debt | Baa3 | BBB- | BBB | |||
Commercial paper | P-3 | A-2 | F2 | |||
Ameren Missouri: | ||||||
Issuer/corporate credit rating | Baa2 | BBB | BBB+ | |||
Secured debt | A3 | A | A | |||
Ameren Illinois: | ||||||
Issuer/corporate credit rating | Baa2 | BBB | BBB- | |||
Secured debt | A3 | A | BBB+ | |||
Senior unsecured debt | Baa2 | BBB | BBB |
• | Ameren's strategy for earning competitive returns on its rate-regulated investments involves meeting customer energy |
• | In July 2013, Illinois enacted a law called the Natural Gas Consumer, Safety and Reliability Act, that enables Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provide additional ICC oversight of natural gas utility performance. The legislation allows natural gas utilities the option to file, and requires the ICC to approve, a rate rider mechanism to provide for recovery of costs associated with certain categories of investment to improve the safety and reliability of the state’s natural gas infrastructure. The law is effective immediately. Ameren Illinois is currently evaluating when to participate in this regulatory framework. Ameren Illinois anticipates it will increase its natural gas capital expenditures when it ultimately elects to participate in the new law’s regulatory framework. |
• | In December 2012, the ICC issued an order with respect to Ameren Illinois' update IEIMA filing approving an electric delivery service revenue requirement that was a $70 million decrease from the requirement allowed in the pre-IEIMA 2010 electric delivery service rate order. The new rates became effective on January 1, 2013. These rates will impact Ameren Illinois’ cash flows during 2013, but not its operating revenues, which are instead impacted by the IEIMA’s 2013 revenue requirement reconciliation discussed below. |
• | 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' 2013 electric delivery service revenues will be based on its 2013 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking framework. The 2013 revenue requirement is expected to be higher than the 2012 revenue requirement due to expected increases in recoverable costs and rate base growth, even though the amount added to the monthly average yields of the 30-year United States treasury bonds decreased to 580 basis points in 2013 from 590 basis points in 2012. |
• | In April 2013, Ameren Illinois filed its annual electric delivery formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. In July 2013, the update filing was revised based on the enactment of May 2013 amendments to the IEIMA. Pending ICC approval, the update filing, as filed by Ameren Illinois, will result in a $38 million decrease in Ameren Illinois’ electric delivery revenue requirement beginning in January 2014. The ICC staff has submitted testimony recommending a $60 million decrease in Ameren Illinois' electric delivery revenue requirement. An ICC decision with respect to the revised update filing is expected in December 2013 and will establish rates for all of 2014. These rates will impact Ameren Illinois’ cash flows during 2014, but not its operating revenues, which are instead impacted by the IEIMA’s 2014 revenue requirement reconciliation. |
• | In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service. The current request, as revised in July 2013, seeks to increase annual revenues for natural gas delivery service by $50 million. The ICC staff is recommending a $24 million increase in Ameren Illinois’ annual revenues for natural gas service. In an attempt to reduce regulatory lag, Ameren Illinois used a future test year, 2014, in this proceeding. A decision in this proceeding is required by December 2013. |
• | In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million, including $84 million related to an anticipated increase in normalized net energy costs above the net energy costs included in base rates previously authorized by the MoPSC in its 2011 electric rate order. The annual increase also includes $80 million for recovery of the costs associated with energy efficiency programs under the MEEIA. The remaining annual increase of $96 million approved by the MoPSC was for energy infrastructure investments and other non-energy costs, including $10 million for increased pension and other post-employment benefit costs and $6 million for increased amortization of regulatory assets. The new rates became effective on January 2, 2013. |
• | The MoPSC's December 2012 electric rate order approved Ameren Missouri's implementation of MEEIA megawatthour savings targets, energy efficiency programs, and associated cost recovery mechanisms and incentive awards. Beginning in 2013, Ameren Missouri will invest $147 million over three years for energy efficiency programs. |
• | As they continue to experience cost increases and make infrastructure investments, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and Ameren Illinois will also seek legislative solutions to address cost recovery pressures. These pressures include a weak economy, customer conservation efforts, the impacts of energy efficiency programs, increased investments and expected future investments for environmental compliance, system reliability improvements, and new baseload capacity, including renewable energy requirements. Increased investments also result in higher depreciation and financing costs. Increased costs are also expected from rising employee benefit costs, higher property and income taxes, and higher insurance premiums as a result of insurance market conditions and industry loss experience, among other things. |
• | Ameren and Ameren Missouri are pursuing recovery from insurers, through litigation, for reimbursement of unpaid liability insurance claims for a December 2005 breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. |
• | Ameren Missouri completed a scheduled refueling and maintenance outage at its Callaway energy center during the second quarter of 2013. The next scheduled refueling and maintenance outage will be in the fall of 2014. During a scheduled outage, which occurs every 18 months, maintenance expense will increase. Additionally, depending |
• | Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. Environmental regulations, as well as future initiatives related to greenhouse gas emissions, could result in significant increases in capital expenditures and operating costs that could be prohibitive at some of Ameren Missouri's coal-fired energy centers, particularly at its Meramec energy center. The expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures for their continued operation. |
• | Ameren continues to pursue its plans to invest in electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the building of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. Design and planning work on the first sections of this project have begun and right-of-way acquisitions are scheduled to commence in late 2013 after receipt of a certificate of public convenience and necessity, which ATXI requested from the ICC in November 2012. Construction is expected to begin in 2014. The first sections of the Illinois Rivers project are expected to be completed in 2016. The last section of this project is expected to be completed in 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects approved by MISO in its transmission expansion plan. These two projects are expected to be completed in 2018. The total investment in these three projects is expected to be more than $1.3 billion through 2019. FERC has approved transmission rate incentives for the three MISO-approved projects as well as for the Big Muddy River project. The Big Muddy River project, located primarily in southern Illinois, may be evaluated for inclusion in MISO's future transmission expansion plans. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $1 billion in electric transmission assets over the next five years to address load growth and reliability requirements. |
• | In November 2012, FERC approved a forward-looking rate calculation with an annual revenue requirement reconciliation for Ameren Illinois' electric transmission business. Based on its forward-looking rate calculation, on January 1, 2013, Ameren Illinois adjusted its electric transmission rates to reflect an increase in its transmission revenue requirement of $29 million. The increase in Ameren Illinois' transmission revenue requirement is subject to an annual revenue requirement reconciliation, which could |
• | In July 2013, the weather conditions in the Midwest market and in Ameren's electric utility companies' service territories were unseasonably mild. Cooling degree-days in Ameren's service territories during July 2013 were 19% lower than normal July weather conditions and were 46% lower than July 2012. This mild weather will have an unfavorable impact on the Ameren Companies' results of operations. |
• | On July 26, 2013, a small fire occurred in the turbine building, located in a non-nuclear section of the Callaway energy center. There was no release of radioactivity to the environment above normal operating limits. The energy center is currently out of service while an assessment is conducted to determine the extent of the damage, which is currently believed to be minimal. |
• | For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, the FAC prudence reviews, Ameren Missouri’s efforts to build additional nuclear generation, Taum Sauk matters, and separate FERC orders impacting Ameren Missouri and Ameren Illinois, see Note 3 - Rate and Regulatory Matters, Note 10 - Commitments and Contingencies and Note 11 - Callaway Energy Center under Part I, Item 1, of this report and Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. |
• | On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 2 - Divestiture Transactions and Discontinued Operations under Part I, Item 1 of this report for additional information. Under the terms of the transaction agreement, Ameren is required to operate its Merchant Generation business in the ordinary course through the transaction closing date, which is expected to occur in the fourth quarter of 2013. However, if Ameren does not complete its divestiture of New AER, Ameren will continue to reduce, and ultimately eliminate, the Merchant Generation segment’s reliance on Ameren’s financial support. |
• | Completion of the divestiture of New AER to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of AER’s divestiture of New AER and Genco’s sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. On July 26, 2013, FERC issued an order seeking additional information. In early August 2013, AER and Dynegy responded to FERC’s request for additional information. Several wholesale customers filed a protest with FERC regarding the application. Separately, as a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same terms as, AER’s variance of the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. |
• | Ameren has commenced a sale process for the Elgin, Gibson City, and Grand Tower gas-fired energy centers and expects a third-party sale will be completed during 2013. |
• | Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City, and Grand Tower energy centers disposal group each met the criteria for discontinued operations presentation, Ameren suspended recording depreciation on these assets in March 2013. |
• | Based on current projections for 2013, excluding the put option receipts, AER expects its operating cash flows to approximate its nonoperating cash flow requirements in 2013. Included in this 2013 projection, AER expects to receive income tax benefits through the tax allocation agreement with Ameren and its non-AER affiliates of approximately $65 million. These estimates may change significantly depending on the taxable income or loss of Ameren and each of its subsidiaries and also assume Ameren's continued ownership of AER through 2013. |
• | In 2012, Marketing Company filed a notice with MISO of its intent to cease operations for one of the three units at AERG's E.D. Edwards energy center. MISO determined that AERG’s operation of that unit was required for system reliability purposes. This designation changes the pricing structure MISO uses to compensate Marketing Company for the generation from that one unit at the E.D. Edwards energy center. MISO and Marketing Company disagree with the level of revenue required to continue to have the unit available for reliability purposes. Depending on MISO’s reliability requirements, this rate structure could continue through 2016, although MISO could notify Marketing Company that it no longer needs the E.D. Edwards unit for reliability purposes and terminate the agreement after a 90-day notification. Ameren will not recognize any revenue related to this reliability contract for the E.D. Edwards unit until FERC rules on the appropriate compensation level. In July 2013, AERG submitted a series of filings with FERC requesting cost recovery including depreciation expense, return on rate base costs, and associated taxes in the revenue required to continue to have the E.D. Edwards unit available for reliability purposes. If Ameren’s ownership of AER continues through 2013, Ameren estimates it could record revenues of between $9 million and $22 million in 2013 as a result of this reliability contract. |
• | The Merchant Generation segment expects to have available generation from its coal-fired energy centers of 31 million megawatthours in any given year. However, based on currently expected power prices, the Merchant Generation segment expects to generate approximately 28 million megawatthours in 2013, with approximately 94% of this generation expected to be from coal-fired energy centers. |
• | Power prices in the Midwest affect the amount of revenues and cash flows the Merchant Generation segment can |
• | As of June 30, 2013, Marketing Company had sold forward approximately 28 million megawatthours for 2013, at an average price of $36 per megawatthour. Megawatthours sold forward in excess of Merchant Generation’s actual generation will be purchased from the market as needed. |
• | As of June 30, 2013, for 2013, Merchant Generation had hedged fuel costs for approximately 26 million megawatthours of coal and up to 26 million megawatthours of base transportation at about $23 per megawatthour. |
• | Upon the divestiture of New AER, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER as of the closing date of such divestiture and provide such additional credit support as required by contracts entered into prior to the closing date, in each case for up to 24 months after the closing. See Note 9 - Related Party Transactions under Part I, Item 1 of this report for additional information. |
• | Ameren anticipates the reduction in employees caused by the divestiture of New AER will result in a curtailment in its pension and postretirement benefit plans. Ameren anticipates the curtailment will result in a gain to reflect the removal of AER active employees who are not yet eligible to retire. The previously accrued liability for AER employees will remain in Ameren's pension and postretirement benefit plans; however, no additional benefits will be earned after closing. |
• | The Ameren Companies seek to maintain access to the capital markets at commercially attractive rates in order to fund their businesses. The Ameren Companies seek to enhance regulatory frameworks and returns in order to improve cash flows, credit metrics, and related access to capital for Ameren's rate-regulated businesses. |
• | The use of continuing operating cash flows and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit as was the case at June 30, 2013, for Ameren. The working capital deficit of $181 million as of June 30, 2013, was primarily the result of Ameren’s $425 million 8.875% senior unsecured notes, Ameren Missouri’s $200 million 4.65% senior secured notes and $104 million 5.50% senior secured notes, and Ameren Illinois’ $150 million 8.875% senior secured notes, all of which will mature within the next twelve months. Ameren is currently evaluating refinancing options for these notes including, in part, through the issuance of long-term notes. Under the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity. |
• | As of June 30, 2013, Ameren had approximately $670 million in federal income tax net operating loss carryforwards (Ameren Missouri - $175 million and Ameren Illinois - $190 million) and $90 million in federal income tax credit carryforwards (Ameren Missouri - $12 million and Ameren Illinois - $- million). Consistent with the tax allocation agreement, these carryforwards are expected to partially offset 2013 income tax liabilities for Ameren Missouri, and into 2015 for Ameren and Ameren Illinois. These amounts exclude any additional net operating losses that will be generated by the New AER divestiture transaction. The tax benefits from these losses are currently recorded as a deferred tax asset on Ameren's balance sheet. |
• | In December 2011, the IRS issued new guidance on the treatment of amounts paid to acquire, produce or improve tangible property and dispositions of such property with respect to electric transmission, distribution, and generation assets as well as natural gas transmission and distribution assets. These new rules are required to be implemented no later than January 1, 2014. In addition, in April 2013, the IRS issued new guidance defining when expenditures to maintain, replace or improve steam or electric power generation property must be capitalized. This April 2013 guidance may change how Ameren determines whether expenditures related to plant and equipment are deducted as repairs or capitalized for income tax purposes. Until Ameren completes its evaluation of the new guidance, Ameren cannot estimate its impact on Ameren's results of operation, financial position, and liquidity. |
• | In November 2012, the Ameren Companies entered into multiyear credit agreements that cumulatively provide $2.1 billion of credit through November 14, 2017. See Note 4 - Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the 2012 Credit Agreements. Ameren, Ameren Missouri, and Ameren Illinois believe that their liquidity is adequate given their expected operating cash flows, capital expenditures, and related financing plans. However, there can be no assurance that significant changes in economic conditions, disruptions in the capital and credit markets, or other unforeseen events will not materially affect their ability to execute their expected operating, capital or financing plans. |
2013 | 2014 | 2015 - 2017 | ||||||
Ameren: | ||||||||
Coal | 100 | % | 100 | % | 98 | % | ||
Coal transportation | 100 | 98 | 98 | |||||
Nuclear fuel | 100 | 99 | 52 | |||||
Natural gas for generation | 53 | 9 | 2 | |||||
Natural gas for distribution(a) | 56 | 24 | 6 | |||||
Purchased power for Ameren Illinois(b) | 100 | 100 | 50 | |||||
Ameren Missouri: | ||||||||
Coal | 100 | % | 100 | % | 98 | % | ||
Coal transportation | 100 | 98 | 98 | |||||
Nuclear fuel | 100 | 99 | 52 | |||||
Natural gas for generation | 53 | 9 | 2 | |||||
Natural gas for distribution(a) | 59 | 29 | 15 | |||||
Ameren Illinois: | ||||||||
Natural gas for distribution(a) | 56 | % | 23 | % | 4 | % | ||
Purchased power(b) | 100 | 100 | 50 |
(a) | Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2013 represents November 2013 through March 2014. The year 2014 represents November 2014 through March 2015. This continues each successive year through March 2018. |
(b) | Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. |
Three Months Ended June 30, 2013 | Ameren | Ameren Missouri | Ameren Illinois | ||||||||
Fair value of contracts at beginning of period, net | $ | (146 | ) | $ | (4 | ) | $ | (142 | ) | ||
Contracts realized or otherwise settled during the period | 11 | (3 | ) | 14 | |||||||
Changes in fair values attributable to changes in valuation technique and assumptions | — | — | — | ||||||||
Fair value of new contracts entered into during the period | 36 | 37 | (1 | ) | |||||||
Other changes in fair value | (27 | ) | (5 | ) | (22 | ) | |||||
Fair value of contracts outstanding at end of period, net | $ | (126 | ) | $ | 25 | $ | (151 | ) | |||
Six Months Ended June 30, 2013 | |||||||||||
Fair value of contracts at beginning of year, net | $ | (201 | ) | $ | 3 | $ | (204 | ) | |||
Contracts realized or otherwise settled during the period | 42 | (11 | ) | 53 | |||||||
Changes in fair values attributable to changes in valuation technique and assumptions | — | — | — | ||||||||
Fair value of new contracts entered into during the period | 36 | 38 | (2 | ) | |||||||
Other changes in fair value | (3 | ) | (5 | ) | 2 | ||||||
Fair value of contracts outstanding at end of period, net | $ | (126 | ) | $ | 25 | $ | (151 | ) |
Sources of Fair Value | Maturity Less than 1 Year | Maturity 1-3 Years | Maturity 4-5 Years | Maturity in Excess of 5 Years | Total Fair Value | ||||||||||||||
Ameren: | |||||||||||||||||||
Level 1 | $ | (3 | ) | $ | (2 | ) | $ | — | $ | — | $ | (5 | ) | ||||||
Level 2(a) | (48 | ) | (30 | ) | (1 | ) | — | (79 | ) | ||||||||||
Level 3(b) | 29 | (21 | ) | (19 | ) | (31 | ) | (42 | ) | ||||||||||
Total | $ | (22 | ) | $ | (53 | ) | $ | (20 | ) | $ | (31 | ) | $ | (126 | ) | ||||
Ameren Missouri: | |||||||||||||||||||
Level 1 | $ | (3 | ) | $ | (2 | ) | $ | — | $ | — | $ | (5 | ) | ||||||
Level 2(a) | (4 | ) | (2 | ) | — | — | (6 | ) | |||||||||||
Level 3(b) | 36 | — | — | — | 36 | ||||||||||||||
Total | $ | 29 | $ | (4 | ) | $ | — | $ | — | $ | 25 | ||||||||
Ameren Illinois: | |||||||||||||||||||
Level 1 | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||
Level 2(a) | (44 | ) | (28 | ) | (1 | ) | — | (73 | ) | ||||||||||
Level 3(b) | (7 | ) | (21 | ) | (19 | ) | (31 | ) | (78 | ) | |||||||||
Total | $ | (51 | ) | $ | (49 | ) | $ | (20 | ) | $ | (31 | ) | $ | (151 | ) |
(a) | Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed-price vs. floating over-the-counter natural gas swaps. |
(b) | Principally power forward contract values based on information from external sources, historical results, and our estimates. Level 3 also includes option contract values based on a Black Scholes model. |
(a) | Evaluation of Disclosure Controls and Procedures |
(b) | Changes in Internal Controls over Financial Reporting |
• | the request for FERC and FCC approvals, as well as the Illinois Pollution Control Board’s decision whether to grant a variance of the Illinois MPS requirements for the New AER energy centers to IPH, in connection with Ameren’s divestiture of New AER to IPH; |
• | Genco’s request for FERC approval to transfer the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley; |
• | appeals of the MoPSC’s December 2012 electric rate order; |
• | Ameren Illinois’ appeal of the ICC’s 2012 electric distribution rate orders in its initial and update IEIMA filings; |
• | a natural gas delivery service rate proceeding and an electric distribution formula update filing for Ameren Illinois pending before the ICC; |
• | FERC litigation to determine wholesale distribution revenues for five of Ameren Illinois’ wholesale customers; |
• | Entergy’s rehearing request of a FERC May 2012 order requiring Entergy to refund to Ameren Missouri additional charges Ameren Missouri paid under an expired power purchase agreement; |
• | Ameren Illinois’ request for rehearing of FERC’s July 2012 and June 2013 orders regarding the inclusion of acquisition premiums in Ameren Illinois’ transmission rates; |
• | ATXI's request for a certificate of public convenience and necessity and project approval from the ICC for the Illinois Rivers project; |
• | the EPA’s Clean Air Act-related litigation filed against Ameren Missouri and NSR investigations at Genco and AERG; |
• | remediation matters associated with former MGP and waste disposal sites of the Ameren Companies; |
• | litigation associated with the breach of the upper reservoir at Ameren Missouri’s Taum Sauk pumped-storage hydroelectric energy center; |
• | Ameren Illinois' receipt of tax liability notices relating to prior-period electric and natural gas municipal taxes; and |
• | asbestos-related litigation associated with Ameren, Ameren Missouri, and Ameren Illinois. |
Period | (a) Total Number of Shares (or Units) Purchased(a) | (b) Average Price Paid per Share (or Unit) | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | ||||||||
April 1 - April 30, 2013 | — | $ | — | — | — | |||||||
May 1 - May 31, 2013 | 1,895 | 36.03 | — | — | ||||||||
June 1 - June 30, 2013 | 2,499 | 34.06 | — | — | ||||||||
Total | 4,394 | $ | 34.91 | — | — |
(a) | Included in May and June were a total of 4,394 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren's 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren's obligations for Ameren board of directors' compensation awards. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | |||
Material Contracts | ||||||
10.1 | Ameren Ameren Missouri | *Performance Stock Bonus Award Agreement, dated April 23, 2013, between Ameren and Adam C. Heflin | ||||
Statement re: Computation of Ratios | ||||||
12.1 | Ameren | Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges | ||||
12.2 | Ameren Missouri | Ameren Missouri’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | ||||
12.3 | Ameren Illinois | Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | ||||
Rule 13a-14(a) / 15d-14(a) Certifications | ||||||
31.1 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren | ||||
31.2 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren | ||||
31.3 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri | ||||
31.4 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri | ||||
31.5 | Ameren Illinois | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois | ||||
31.6 | Ameren Illinois | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois | ||||
Section 1350 Certifications | ||||||
32.1 | Ameren | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren | ||||
32.2 | Ameren Missouri | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri | ||||
32.3 | Ameren Illinois | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois | ||||
Interactive Data File | ||||||
101.INS** | Ameren Companies | XBRL Instance Document | ||||
101.SCH** | Ameren Companies | XBRL Taxonomy Extension Schema Document | ||||
101.CAL** | Ameren Companies | XBRL Taxonomy Extension Calculation Linkbase Document | ||||
101.LAB** | Ameren Companies | XBRL Taxonomy Extension Label Linkbase Document | ||||
101.PRE** | Ameren Companies | XBRL Taxonomy Extension Presentation Linkbase Document | ||||
101.DEF** | Ameren Companies | XBRL Taxonomy Extension Definition Document |
AMEREN CORPORATION (Registrant) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
UNION ELECTRIC COMPANY (Registrant) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
AMEREN ILLINOIS COMPANY (Registrant) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
Ameren Corporation By: /s/ Mark C. Lindgren |
By: /s/ Adam C. Heflin |
Adam C. Heflin |
Six Months Ended June 30, | |||
2013 (a) | |||
Earnings available for fixed charges, as defined: | |||
Net income from continuing operations attributable to Ameren Corporation | $ | 159,288 | |
Tax expense based on income | 101,377 | ||
Fixed charges excluding preferred stock dividends tax adjustment (b) | 217,092 | ||
Earnings available for fixed charges, as defined | $ | 477,757 | |
Fixed charges, as defined: | |||
Interest expense on short-term and long-term debt (b) | $ | 198,407 | |
Estimated interest cost within rental expense | 3,597 | ||
Amortization of net debt premium, discount, and expenses | 11,866 | ||
Subsidiary preferred stock dividends | 3,222 | ||
Adjust preferred stock dividends to pretax basis | 1,932 | ||
Total fixed charges, as defined | $ | 219,024 | |
Consolidated ratio of earnings to fixed charges | 2.18 |
(a) | Excludes discontinued operations. |
(b) | Includes interest expense related to uncertain tax positions. |
Six Months Ended June 30, | |||
2013 | |||
Earnings available for fixed charges, as defined: | |||
Net income | $ | 125,344 | |
Tax expense based on income | 68,148 | ||
Fixed charges (a) | 125,119 | ||
Earnings available for fixed charges, as defined | $ | 318,611 | |
Fixed charges, as defined: | |||
Interest expense on short-term and long-term debt (a) | $ | 119,580 | |
Estimated interest cost within rental expense | 1,784 | ||
Amortization of net debt premium, discount, and expenses | 3,755 | ||
Total fixed charges, as defined | $ | 125,119 | |
Ratio of earnings to fixed charges | 2.55 | ||
Earnings required for combined fixed charges and preferred stock dividends: | |||
Preferred stock dividends | $ | 1,710 | |
Adjustment to pretax basis | 930 | ||
$ | 2,640 | ||
Combined fixed charges and preferred stock dividend requirements | $ | 127,759 | |
Ratio of earnings to combined fixed charges and preferred stock dividend requirements | 2.49 |
(a) | Includes interest expense related to uncertain tax positions. |
Six Months Ended June 30, | |||
2013 | |||
Earnings available for fixed charges, as defined: | |||
Net income | $ | 64,006 | |
Tax expense based on income | 42,407 | ||
Fixed charges (a) | 68,706 | ||
Earnings available for fixed charges, as defined | $ | 175,119 | |
Fixed charges, as defined: | |||
Interest expense on short-term and long-term debt (a) | $ | 59,774 | |
Estimated interest cost within rental expense | 1,814 | ||
Amortization of net debt premium, discount, and expenses | 7,118 | ||
Total fixed charges, as defined | $ | 68,706 | |
Ratio of earnings to fixed charges | 2.55 | ||
Earnings required for combined fixed charges and preferred stock dividends: | |||
Preferred stock dividends | $ | 1,512 | |
Adjustment to pretax basis | 1,002 | ||
$ | 2,514 | ||
Combined fixed charges and preferred stock dividend requirements | $ | 71,220 | |
Ratio of earnings to combined fixed charges and preferred stock dividend requirements | 2.46 |
(a) | Includes interest expense related to uncertain tax positions. |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Thomas R. Voss |
Thomas R. Voss Chairman, President and Chief Executive Officer (Principal Executive Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Warner L. Baxter |
Warner L. Baxter Chairman, President and Chief Executive Officer (Principal Executive Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Richard J. Mark |
Richard J. Mark Chairman, President and Chief Executive Officer (Principal Executive Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
(1) | The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and |
(2) | The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
/s/ Thomas R. Voss |
Thomas R. Voss Chairman, President and Chief Executive Officer (Principal Executive Officer) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
(1) | The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and |
(2) | The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
/s/ Warner L. Baxter |
Warner L. Baxter Chairman, President and Chief Executive Officer (Principal Executive Officer) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
(1) | The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and |
(2) | The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
/s/ Richard J. Mark |
Richard J. Mark Chairman, President and Chief Executive Officer (Principal Executive Officer) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
Segment Information (Schedule Of Segment Reporting Information By Segment) (Detail) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||||||||
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Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Dec. 31, 2012
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Segment Reporting Information [Line Items] | ||||||||||
External revenues | $ 1,403 | $ 1,402 | $ 2,878 | $ 2,814 | ||||||
Continuing Operations | 105 | 161 | 159 | 198 | ||||||
Total assets | 22,276 | 22,276 | 22,209 | |||||||
Ameren Missouri [Member]
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Segment Reporting Information [Line Items] | ||||||||||
External revenues | 883 | 838 | 1,672 | 1,524 | ||||||
Intersegment revenues | 6 | 6 | 13 | 11 | ||||||
Continuing Operations | 84 | 143 | 124 | 164 | ||||||
Total assets | 13,131 | 13,131 | 13,043 | |||||||
Ameren Illinois Company [Member]
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Segment Reporting Information [Line Items] | ||||||||||
External revenues | 514 | 564 | 1,197 | 1,288 | ||||||
Intersegment revenues | 2 | 3 | ||||||||
Continuing Operations | 31 | 32 | 62 | 59 | ||||||
Total assets | 7,366 | 7,366 | 7,282 | |||||||
Other Segment [Member]
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Segment Reporting Information [Line Items] | ||||||||||
External revenues | 6 | 9 | 2 | |||||||
Intersegment revenues | 1 | 1 | 2 | |||||||
Continuing Operations | (10) | (14) | (27) | (25) | ||||||
Total assets | 1,354 | 1,354 | 1,228 | |||||||
Intersegment Elimination [Member]
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Segment Reporting Information [Line Items] | ||||||||||
External revenues | ||||||||||
Intersegment revenues | (8) | (7) | (17) | (13) | ||||||
Continuing Operations | ||||||||||
Total assets | (1,061) | (1,061) | (944) | |||||||
Segment, Continuing Operations [Member]
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Segment Reporting Information [Line Items] | ||||||||||
External revenues | 1,403 | 1,402 | 2,878 | 2,814 | ||||||
Continuing Operations | 105 | 161 | 159 | 198 | ||||||
Total assets | $ 20,790 | [1] | $ 20,790 | [1] | $ 20,609 | [1] | ||||
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Commitments And Contingencies
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Jun. 30, 2013
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Commitments and Contingencies Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in the notes to our financial statements in this report and in our Form 10-K, will not have a material adverse effect on our results of operations, financial position, or liquidity. Reference is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and Regulatory Matters, Note 14 - Related Party Transactions, and Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K. See also Note 1 - Summary of Significant Accounting Policies, Note 2 - Divestiture Transactions and Discontinued Operations, Note 3 - Rate and Regulatory Matters, Note 9 - Related Party Transactions and Note 11 - Callaway Energy Center in this report. Callaway Energy Center The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at June 30, 2013. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.
The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment was recently announced and is effective September 10, 2013. Owners of a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson. Losses resulting from terrorist attacks are covered under Nuclear Electric Insurance Ltd.’s policies, subject to an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts. If losses from a nuclear incident at the Callaway energy center exceed the limits of, or are not covered by insurance, or if coverage is unavailable, Ameren Missouri is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and Ameren Missouri’s results of operations, financial position, or liquidity. Other Obligations To supply a portion of the fuel requirements of our energy centers, we have entered into various long-term commitments for the procurement of coal, natural gas, nuclear fuel, and methane gas. We also have entered into various long-term commitments for purchased power and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 15 - Commitments and Contingencies under Part II, Item 8, of the Form 10-K. At June 30, 2013, total other obligations related to the procurement of coal, natural gas, nuclear fuel, purchased power, methane gas, and equipment and meter reading services, among other agreements, at Ameren, Ameren Missouri and Ameren Illinois were $7,190 million, $5,026 million, and $2,122 million, respectively. Environmental Matters We are subject to various environmental laws and regulations enforced by federal, state, and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generation, transmission and distribution facilities and natural gas storage, transmission and distribution facilities, our activities involve compliance with diverse environmental laws and regulations. These laws and regulations address emissions, impacts to air, land, and water, noise, protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to obtain approvals, permits, or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires release prevention plans and emergency response procedures. In addition to existing environmental laws and regulations, including the Illinois MPS that applies to AER's coal-fired energy centers in Illinois, the EPA is developing regulations that will have a significant impact on the electric utility industry. These regulations could be particularly burdensome for certain companies, including Ameren, Ameren Missouri, and AER, that operate coal-fired energy centers. Significant new rules proposed or promulgated since the beginning of 2010 include the regulation of greenhouse gas emissions from new energy centers; revised national ambient air quality standards for fine particulates, SO2, and NOx emissions; the CSAPR, which would have required further reductions of SO2 emissions and NOx emissions from energy centers; a regulation governing management of CCR and coal ash impoundments; the MATS, which require reduction of emissions of mercury, toxic metals, and acid gases from energy centers; revised NSPS for particulate matter, SO2, and NOx emissions from new sources; new effluent standards applicable to discharges from steam-electric generating units; and new regulations under the Clean Water Act that could require significant capital expenditures such as new water intake structures or cooling towers at our energy centers. The EPA is expected to propose CO2 limits for existing fossil fuel-fired electric generation units in the future. These new and proposed regulations, if adopted, may be challenged through litigation, so their ultimate implementation as well as the timing of any such implementation is uncertain, as evidenced by the CSAPR being vacated and remanded back to the EPA by the United States Court of Appeals for the District of Columbia Circuit in August 2012. Although many details of these future regulations are unknown, the combined effects of the new and proposed environmental regulations may result in significant capital expenditures and increased operating costs over the next five to ten years for Ameren, Ameren Missouri and AER. Compliance with these environmental laws and regulations could be prohibitively expensive. If they are, these regulations could require us to close or to significantly alter the operation of our energy centers, which could have an adverse effect on our results of operations, financial position, and liquidity, including the impairment of long-lived assets. Failure to comply with environmental laws and regulations might also result in the imposition of fines, penalties, and injunctive measures. The estimates in the tables below contain all of the known capital costs to comply with existing environmental regulations, including the CAIR, and our assessment of the potential impacts of the EPA's proposed regulation for CCR and the MATS as of June 30, 2013. In addition, the estimates assume that CCR will continue to be regarded as nonhazardous. The estimates do not include the impacts of regulations proposed by the EPA under the Clean Water Act in March 2011 regarding cooling water intake structures or the impact of the effluent standards applicable to steam-electric generating units that the EPA proposed in April 2013 as the technology requirements ultimately to be selected in these final rules are not yet known. The estimates shown in the tables below could change significantly depending upon a variety of factors including:
Continuing Operations:
Discontinued Operations:
The following sections describe the more significant environmental laws and rules that affect or could affect our operations. Clean Air Act Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. In March 2005, the EPA issued regulations with respect to SO2 and NOx emissions (the CAIR). The CAIR requires generating facilities in 28 states, including Missouri and Illinois, and the District of Columbia, to participate in cap-and-trade programs to reduce annual SO2 emissions, annual NOx emissions, and ozone season NOx emissions. In December 2008, the United States Court of Appeals for the District of Columbia Circuit remanded the CAIR to the EPA for further action to remedy the rule's flaws, but allowed the CAIR's cap-and-trade programs to remain effective until they are replaced by the EPA. In July 2011, the EPA issued the CSAPR as the CAIR replacement. On December 30, 2011, the United States Court of Appeals for the District of Columbia Circuit issued a stay of the CSAPR. In August 2012, the United States Court of Appeals for the District of Columbia Circuit issued a ruling that vacated the CSAPR in its entirety, finding that the EPA exceeded its authority in imposing the CSAPR's emission limits on states. In January 2013, the full Court of Appeals for the District of Columbia Circuit denied the EPA's request for rehearing. In March 2013, the EPA and certain environmental groups filed an appeal of the Court of Appeals’ remand of CSAPR to the United States Supreme Court. The United States Supreme Court has agreed to consider the appeal and is expected to hear oral arguments and rule on the appeal during its next term, which begins in October 2013 and ends in June 2014. The EPA will continue to administer the CAIR until a new rule is ultimately adopted or the decision to vacate the CSAPR is overturned by the United States Supreme Court. In December 2011, the EPA issued the MATS under the Clean Air Act, which require emission reductions for mercury and other hazardous air pollutants, such as acid gases, toxic metals, and particulate matter by setting emission limits equal to the average emissions of the best performing 12% of existing coal and oil-fired electric generating units. Also, the standards require reductions in hydrogen chloride emissions, which were not regulated previously, and for the first time require continuous monitoring systems for hydrogen chloride, mercury, and particulate matter that are not currently in place. The MATS do not require a specific control technology to achieve the emission reductions. The MATS will apply to each unit at a coal-fired power plant; however in certain cases, emission compliance can be achieved by averaging emissions from similar electric generating units at the same power plant. Compliance is required by April 2015 or, with a case-by-case extension, by April 2016. Ameren Missouri's Labadie and Meramec energy centers requested and were granted extensions to April 2016 to comply with the MATS. Separately, in December 2012, the EPA issued a final rule that made the national ambient air quality standard for fine particulate matter more stringent. States must develop control measures designed to reduce the emission of fine particulate matter below required levels to achieve compliance with the new standard. Such measures may or may not apply to energy centers but could require reductions in SO2 and NOx emissions. Compliance with the rule is required by 2020, or 2025 if an extension of time to achieve compliance is granted. Ameren Missouri and AER are currently evaluating the new standard while the states of Missouri and Illinois develop their attainment plans. In September 2011, the EPA announced that it was implementing the 2008 national ambient air quality standards for ozone. The EPA is required to revisit these standards for ozone again in 2013. The states of Illinois and Missouri will be required to develop attainment plans to comply with the 2008 ambient air quality standards for ozone, which could result in additional emission control requirements for power plants by 2020. Ameren, Ameren Missouri and AER continue to assess the impacts of these new standards. In July 2013, the EPA issued a final rule designating portions of the United States, including parts of Illinois and Missouri, as nonattainment for the national ambient air quality standard for SO2. The effected states must develop plans in the next 18 months to reduce emissions so that they can achieve the ambient air quality standards within five years. Ameren, Ameren Missouri and AER are assessing the impact of this designation. Ameren Missouri's current environmental compliance plan for air emissions from its energy centers includes burning ultra-low-sulfur coal and installing new or optimizing existing pollution control equipment. In July 2011, Ameren Missouri contracted to procure significantly greater volumes of lower-sulfur-content coal than Ameren Missouri's energy centers had historically burned, which allowed Ameren Missouri to eliminate or postpone capital expenditures for pollution control equipment. In 2010, Ameren Missouri completed the installation of two scrubbers at its Sioux energy center to reduce SO2 emissions. Currently, Ameren Missouri's compliance plan assumes the installation of two scrubbers, mercury control technology, and precipitator upgrades at multiple energy centers within its coal-fired fleet during the next 10 years. However, Ameren Missouri is currently evaluating its operations and options to determine how to comply with the MATS and other recently finalized or proposed EPA regulations. In September 2012, the Illinois Pollution Control Board granted AER a variance to extend compliance dates for SO2 emission levels contained in the MPS through December 31, 2019, subject to certain conditions described below. The Illinois Pollution Control Board approved AER's proposed plan to restrict its SO2 emissions through 2014 to levels lower than those previously required by the MPS to offset any environmental impact from the variance. The Illinois Pollution Control Board's order also included the following provisions:
As a condition to IPH’s obligation to complete the acquisition of New AER, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same terms as, AER’s variance related to the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. On July 22, 2013, IPH, AER and Medina Valley, as current and future owners of the coal-fired energy centers, filed a request for a variance with the Illinois Pollution Control Board seeking the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of AER. Under the MPS, AER is required to reduce mercury, NOx and SO2 emissions with declining limits that started in 2009 for mercury and in 2010 for NOx and SO2. The final NOx limit became effective in 2012. The final mercury limit will become effective in 2015 and the final SO2 limit will become effective by the end of 2019. The Illinois Pollution Control Board's September 2012 variance gives AER additional time for economic recovery and related power price improvements necessary to support scrubber installations and other pollution controls at some of AER's energy centers. To comply with the MPS and other air emissions laws and regulations, AER is installing equipment designed to reduce its emissions of mercury, NOx, and SO2. AER has installed three scrubbers at two energy centers. Two additional scrubbers are being constructed at the Newton energy center. AER will continue to review and adjust its compliance plans in light of evolving outlooks for power and capacity prices, delivered fuel costs, emission standards required under environmental laws and regulations, and compliance technologies, among other factors. Environmental compliance costs could be prohibitive at some of Ameren's, Ameren Missouri's and AER's energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets. Emission Allowances The Clean Air Act created marketable commodities called emission allowances under the acid rain program, the NOx budget trading program, and the CAIR. Environmental regulations, including those relating to the timing of the installation of pollution control equipment, fuel mix, and the level of operations will have a significant impact on the number of allowances required for ongoing operations. The CAIR uses the acid rain program's allowances for SO2 emissions and created annual and ozone season NOx allowances. Ameren and Ameren Missouri expect to have adequate allowances for 2013 to avoid needing to make external purchases to comply with these programs. Greenhouse Gas Regulation State and federal authorities, including the United States Congress, have considered initiatives to limit greenhouse gas emissions. Potential impacts from any such legislation or regulation could vary, depending upon proposed CO2 emission limits, the timing of implementation of those limits, the method of distributing any allowances, the degree to which offsets are allowed and available, and provisions for cost-containment measures, such as a “safety valve” provision that provides a maximum price for emission allowances. As a result of our fuel portfolio, our emissions of greenhouse gases vary among our energy centers, but coal-fired power plants are significant sources of CO2. The enactment of a law that restricts emissions of CO2 or requires energy centers to purchase allowances for CO2 emissions could result in a significant rise in rates for electricity and thereby household costs. The burden could fall particularly hard on electricity consumers and upon the economy in the Midwest because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half as much CO2 as coal when burned to produce electricity. Therefore, greenhouse gas regulations could cause the conversion of coal-fired power plants to natural gas, or the construction of new natural gas plants to replace coal-fired power plants. As a result, economy wide shifts to natural gas as a fuel source for electricity generation also could affect the cost of heating for our utility customers and many industrial processes that use natural gas. In December 2009, the EPA issued its “endangerment finding” under the Clean Air Act, which stated that greenhouse gas emissions, including CO2, endanger human health and welfare and that emissions of greenhouse gases from motor vehicles contribute to that endangerment. In March 2010, the EPA issued a determination that greenhouse gas emissions from stationary sources, such as power plants, would be subject to regulation under the Clean Air Act effective the beginning of 2011. As a result of these actions, we are required to consider the emissions of greenhouse gases in any air permit application. Recognizing the difficulties presented by regulating at once virtually all emitters of greenhouse gases, the EPA issued the “Tailoring Rule,” which established new higher emission thresholds beginning in January 2011, for regulating greenhouse gas emissions from stationary sources, such as power plants. The rule requires any source that already has an operating permit to have greenhouse-gas-specific provisions added to its permits upon renewal. Currently, all Ameren energy centers have operating permits that, when renewed, may be modified to address greenhouse gas emissions. The Tailoring Rule also provides that if projects performed at major sources result in an increase in emissions of greenhouse gases over an applicable annual threshold, such projects could trigger permitting requirements under the NSR programs and the application of best available control technology to address greenhouse gas emissions. New major sources are also required to obtain such a permit and to install the best available control technology if their greenhouse gas emissions exceed the applicable emissions threshold. The extent to which the Tailoring Rule could have a material impact on our energy centers depends upon how state agencies apply the EPA's guidelines as to what constitutes the best available control technology for greenhouse gas emissions from power plants and whether physical changes or changes in operations subject to the rule occur at our energy centers. In June 2012, the United States Court of Appeals for the District of Columbia Circuit upheld the Tailoring Rule. Industry groups and a coalition of states filed petitions in April 2013 requesting that the United States Supreme Court review the circuit court’s decision upholding the Tailoring Rule. Separately, in March 2012, the EPA issued the proposed Carbon Pollution Standard for New Power Plants. This proposed NSPS for greenhouse gas emissions would apply only to new fossil-fuel fired energy centers and therefore does not affect any of the Ameren, Ameren Missouri or AER existing energy centers. Ameren anticipates this proposed rule, if enacted, could make the construction of new coal-fired energy centers in the United States prohibitively expensive. A final rule is expected to be issued in 2013. In June 2013, the Obama Administration announced that the EPA has been directed to set carbon emissions standards for both new and existing power plants. The EPA is expected to propose revised carbon regulations for new generating units by September 2013. In addition, the EPA has been directed to propose a carbon standard for existing power plants by June 2014 and to finalize such standard by June 2015. Currently, the Ameren Companies are unable to predict the outcome or impacts of such future regulations. Recent federal court decisions have considered the application of common law causes of action, such as nuisance, to address alleged damages resulting from greenhouse gas emissions. In March 2012, the United States District Court for the Southern District of Mississippi dismissed the Comer v. Murphy Oil lawsuit, which alleged that CO2 emissions from several industrial companies, including Ameren Missouri, Genco and AERG, created atmospheric conditions that intensified Hurricane Katrina, thereby causing property damage. In May 2013, the dismissal of the lawsuit was affirmed by the United States Court of Appeals for the Fifth Circuit. Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would likely result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. These compliance costs could be prohibitive at some of our energy centers as the expected return from these investments, at current market prices for energy and capacity, might not justify the required capital expenditures or their continued operation, which could result in the impairment of long-lived assets. To the extent Ameren Missouri requests recovery of these costs through rates, its regulators might delay or deny timely recovery of these costs. As a result, mandatory limits on the emission of greenhouse gases could have a material adverse impact on Ameren's and Ameren Missouri's results of operations, financial position, and liquidity. NSR and Clean Air Litigation The EPA is engaged in an enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the Clean Air Act when the plants implemented modifications. The EPA's inquiries focus on whether projects performed at power plants triggered various permitting requirements and the installation of pollution control equipment. Commencing in 2005, Genco received a series of information requests from the EPA pursuant to Section 114(a) of the Clean Air Act. The requests sought detailed operating and maintenance history data with respect to Genco's Coffeen, Hutsonville, Meredosia, Newton, and Joppa energy centers and AERG's E.D. Edwards and Duck Creek energy centers. In August 2012, Genco received a Notice of Violation from the EPA alleging violations of permitting requirements including Title V of the Clean Air Act. The EPA contends that projects performed in 1997, 2006, and 2007 at Genco's Newton energy center violated federal law. Ameren believes its defenses to the allegations at Genco described in the Notice of Violation are meritorious, and a recent court decision by the United States Court of Appeals for the Seventh Circuit recently held that similar claims older than five years were barred by the statute of limitations. If not reversed or overturned this decision may provide an additional defense to the allegations in the Newton energy center Notice of Violation. Ameren is unable to predict the outcome of this matter and whether the EPA will address this Notice of Violation administratively or through litigation. Following the issuance of a Notice of Violation in January 2011, the Department of Justice on behalf of the EPA filed a complaint against Ameren Missouri in the United States District Court for the Eastern District of Missouri. The EPA's complaint alleges that in performing projects at its Rush Island coal-fired energy center in 2001, 2003, 2007, and 2010, Ameren Missouri violated provisions of the Clean Air Act and Missouri law. In January 2012, the district court granted, in part, Ameren Missouri's motion to dismiss various aspects of the EPA's penalty claims. The EPA's claims for injunctive relief, including the requirement to install pollution control equipment, remain. Litigation of this matter could take years, and no trial date has been established. Ameren Missouri believes its defenses to the allegations described in the complaint as well as the Notices of Violation are meritorious. Ameren Missouri will defend itself vigorously. However, there can be no assurances that it will be successful in its efforts. Ultimate resolution of these matters could have a material adverse impact on the future results of operations, financial position, and liquidity of Ameren and Ameren Missouri. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. We are unable to predict the ultimate resolution of these matters or the costs that might be incurred. Clean Water Act In March 2011, the EPA announced a proposed rule applicable to cooling water intake structures at existing power plants that have the ability to withdraw more than 2 million gallons of water per day from a body of water and use at least 25% of that water exclusively for cooling. Under the proposed rule, affected facilities would be required either to meet mortality limits for aquatic life impinged on the plant's intake screens or to reduce intake velocity to a specified level. The proposed rule also requires existing power plants to meet site-specific entrainment standards or to reduce the cooling water intake flow commensurate with the intake flow of a closed-cycle cooling system. The final rule is scheduled to be issued in November 2013, with compliance expected within eight years thereafter. All coal-fired, nuclear, and combined cycle energy centers at Ameren, Ameren Missouri and AER with cooling water systems are subject to this proposed rule. The proposed rule did not mandate cooling towers at existing facilities, as other technology options potentially could meet the site-specific standards. Ameren, Ameren Missouri and AER are currently evaluating the proposed rule, and their assessment of the proposed rule's impacts is ongoing. Therefore, we cannot predict at this time the capital or operating costs associated with compliance. The proposed rule, if adopted, could have an adverse effect on our results of operations, financial position, and liquidity if its implementation requires the installation of cooling towers at our energy centers. In April 2013, the EPA announced its proposal to revise the effluent limitation guidelines applicable to steam electric generating units under the Clean Water Act. Effluent limitation guidelines are national standards for wastewater discharges to surface water that are based on the effectiveness of available control technology. The proposed revision targets wastewater streams associated with fluegas desulfurization (i.e. scrubbers), fly ash, bottom ash, fluegas mercury control, CCR leachate from landfills and impoundments, nonchemical metal cleaning, and gasification of fuels. The EPA’s proposal identifies several alternatives for addressing these waste streams, including best management practices for CCR impoundments. The EPA’s proposed rule raised several compliance options that would prohibit effluent discharges of certain, but not all, waste streams and impose more stringent limitations on certain components in wastewater discharges from power plants. If enacted as proposed, Ameren Missouri and AER would be subject to the revised limitations beginning as early as July 1, 2017, but no later than July 1, 2022. We are reviewing the proposed rule and evaluating its potential impact on our operations if enacted as proposed. The EPA expects to finalize the rule in 2014. Remediation We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of their degree of fault, the legality of original disposal, or the ownership of a disposal site. Ameren Missouri and Ameren Illinois have each been identified by the federal or state governments as a potentially responsible party (PRP) at several contaminated sites. As part of the transfer of generation assets by our rate-regulated utility operations in Illinois to Genco in May 2000 and to AERG in October 2003, Ameren Illinois’ predecessor companies contractually agreed to indemnify Genco and AERG for claims relating to pre-existing environmental conditions at the transferred sites. The plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois will be amended as part of the transaction agreement for Ameren to divest New AER to IPH. The agreements will specify that all environmental liabilities associated with the Meredosia and Hutsonville energy centers will be assumed by Medina Valley. The agreements will also specify that Genco and AERG will no longer be indemnified by Ameren Illinois with respect to the environmental liabilities associated with Genco’s Newton and Coffeen energy centers and AERG’s E.D. Edwards and Duck Creek energy centers. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren’s divestiture of New AER. As of June 30, 2013, Ameren Illinois owned or was otherwise responsible for 44 former MGP sites in Illinois. These are in various stages of investigation, evaluation, remediation, and closure. Based on current estimated plans, Ameren Illinois could substantially conclude remediation efforts at most of these sites by 2018. The ICC permits Ameren Illinois to recover remediation and litigation costs associated with its former MGP sites from its electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred. Costs are subject to annual review by the ICC. As of June 30, 2013, Ameren Missouri has one remaining former MGP site for which remediation is scheduled. Remediation is complete at the other Ameren Missouri former MGP sites. Ameren Missouri does not currently have a rate rider mechanism that permits it to recover from utility customers remediation costs associated with MGP sites. The following table presents, as of June 30, 2013, the estimated obligation to complete the remediation of these former MGP sites.
The scope and extent to which these former MGP sites are remediated may increase as remediation efforts continue. Considerable uncertainty remains in these estimates as many factors can influence the ultimate actual costs, including site specific unanticipated underground structures, the degree to which groundwater is encountered, regulatory changes, local ordinances, and site accessibility. The actual costs may vary substantially from these estimates. Ameren Illinois utilized an off-site landfill, which Ameren Illinois did not own, in connection with its operation of the Coffeen energy center prior to the formation of Genco. While not currently mandated, Ameren Illinois may be required to perform certain remediation activities associated with that landfill. As of June 30, 2013, Ameren Illinois estimated the obligation related to the cleanup at $0.5 million to $6 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Ameren Illinois is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of June 30, 2013, Ameren Illinois recorded a liability of $0.8 million to represent its estimate of the obligation for these sites. Ameren Missouri has responsibility for the investigation and potential cleanup of two waste sites in Missouri as a result of federal agency mandates. One of the cleanup sites is a former coal tar distillery located in St. Louis, Missouri. In 2008, the EPA issued an administrative order to Ameren Missouri pertaining to this distillery operated by Koppers Company or its predecessor and successor companies. Ameren Missouri is the current owner of the site, but Ameren Missouri did not conduct any of the manufacturing operations involving coal tar or its byproducts. Ameren Missouri, along with two other PRPs, is currently performing a site investigation. As of June 30, 2013, Ameren Missouri estimated its obligation at $2 million to $5 million. Ameren Missouri recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate. Ameren Missouri's other active federal agency-mandated cleanup site in Missouri is a site in Cape Girardeau. Ameren Missouri was a customer of an electrical equipment repair and disposal company that previously operated a facility at this site. A trust was established in the early 1990s by several businesses and governmental agencies to fund the investigation and cleanup of this site, which was completed in 2005. Ameren Missouri anticipates that this trust fund will be sufficient to complete the remaining adjacent off-site cleanup, and it therefore has no recorded liability at June 30, 2013, for this site. Ameren Missouri also has a federal agency mandate to complete an investigation for a site in Illinois. In 2000, the EPA notified Ameren Missouri and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, Ameren Missouri operated an energy center adjacent to Sauget Area 2. Ameren Missouri currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order on Consent, Ameren Missouri joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2. The Sauget Area 2 investigations overseen by the EPA have been completed. The results have been submitted to the EPA, and a record of decision is expected in 2013. Once the EPA has approved the proposed site remedies, it will begin negotiations with various PRPs regarding implementation. Over the last several years, numerous other parties have joined the PRP group. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia's former chemical waste landfill in Sauget Area 2. As of June 30, 2013, Ameren Missouri estimated its obligation related to Sauget Area 2 at $0.3 million to $10 million. Ameren Missouri recorded a liability of $0.3 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate. In December 2012, Ameren Missouri signed an administrative order with the EPA and agreed to investigate soil and groundwater conditions at an Ameren Missouri owned substation in St. Charles, Missouri. As of June 30, 2013, Ameren Missouri estimated the obligation related to the cleanup at $1.7 million to $4.5 million. Ameren Missouri recorded a liability of $1.7 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. Our operations or those of our predecessor companies involve the use of, disposal of, and in appropriate circumstances, the cleanup of substances regulated under environmental laws. We are unable to determine whether such practices will result in future environmental commitments or will affect our results of operations, financial position, or liquidity. Ash Management There has been activity at both state and federal levels regarding additional regulation of ash pond facilities and CCR. In May 2010, the EPA announced proposed new regulations regarding the regulatory framework for the management and disposal of CCR, which could affect future disposal and handling costs at our energy centers. Those proposed regulations include two options for managing CCRs under either solid or hazardous waste regulations, but either alternative would allow for some continued beneficial uses, such as recycling of CCR without classifying it as waste. As part of its proposal, the EPA is considering alternative regulatory approaches that require coal-fired power plants either to close surface impoundments, such as ash ponds, or to retrofit such facilities with liners. Existing impoundments and landfills used for the disposal of CCR would be subject to groundwater monitoring requirements and requirements related to closure and postclosure care under the proposed regulations. The EPA announced that its April 2013 proposed revisions to the effluent limitations applicable to steam electric generating units would apply to ash ponds and CCR management and that it intended to align this proposal with the CCR rules proposed in May 2010. Additionally, in January 2010, the EPA announced its intent to develop regulations establishing financial responsibility requirements for the electric generation industry, among other industries, and it specifically discussed CCR as a reason for developing the new requirements. Ameren, Ameren Missouri and AER are currently evaluating all of the proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the ash ponds should be altered. Ameren, Ameren Missouri and AER are evaluating the potential costs associated with compliance with the proposed regulation of CCR impoundments and landfills, which could be material, if such regulations are adopted. The Illinois EPA has issued violation notices with respect to groundwater conditions existing at Genco’s ash pond systems. AER filed a proposed rulemaking with the Illinois Pollution Control Board which, if approved, would provide for the systematic and eventual closure of ash ponds. The Illinois EPA is in the process of developing its own ash pond impoundment rulemaking and anticipates filing proposed rules with the Illinois Pollution Control Board in 2013. The rulemaking process could take up to two years to complete. During the first quarter of 2013, Genco and AERG revised their ARO fair value estimates relating to their ash ponds to reflect expected retirements dates. See Note 1 - Summary of Significant Accounting Policies for additional information related to our asset retirement obligations. Pumped-storage Hydroelectric Facility Breach In December 2005, there was a breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center. This resulted in significant flooding in the local area, which damaged a state park. The rebuilt Taum Sauk energy center became fully operational in April 2010. Ameren Missouri had liability insurance coverage for the Taum Sauk incident, subject to certain limits and deductibles. As of June 30, 2013, Ameren Missouri had an insurance receivable balance of $68 million. Ameren Missouri's results of operations, financial position and liquidity could be adversely affected if its remaining liability insurance claims are not paid by insurers. In June 2010, Ameren Missouri sued an insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the litigation, filed in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed that the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. In January 2011, the district court ruled that the parties must first pursue alternative dispute resolution under the terms of their coverage agreement. Ameren Missouri appealed the January 2011 ruling to the United States Court of Appeals for the Eighth Circuit. In August 2012, the court of appeals remanded the case to the district court for consideration of whether Missouri law voids the alternative dispute resolution provision of the insurance policy. Separately, in April 2012, Ameren Missouri sued a second insurance company that was providing Ameren Missouri with liability coverage on the date of the Taum Sauk incident. In the April 2012 litigation, which is pending in the United States District Court for the Eastern District of Missouri, Ameren Missouri claimed the insurance company breached its duty to indemnify Ameren Missouri for the losses resulting from the incident. The insurance company filed a motion to compel arbitration, which the district court denied. In April 2013, the United States Court of Appeals for the Eighth Circuit affirmed the district court’s denial of the insurer’s motion and remanded the case to the district court. Asbestos-related Litigation Ameren, Ameren Missouri and Ameren Illinois have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case varies with the average number of parties being 80 as of June 30, 2013. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants. The claims filed against Ameren, Ameren Missouri and Ameren Illinois allege injury from asbestos exposure during the plaintiffs' activities at our present or former energy centers. Former CIPS energy centers are now owned by Genco, and former CILCO energy centers are now owned by AERG. As a condition to the transfer of ownership of the CIPS and CILCO energy centers, CIPS and CILCO, now Ameren Illinois, contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising or existing from activities prior to the transfer. The plant transfer agreement between Genco and Ameren Illinois and the plant transfer agreement between AERG and Ameren Illinois each will be amended pursuant to the transaction agreement in which Ameren agrees to divest New AER to IPH. The amended plant transfer agreements will provide that Ameren Illinois will continue to retain asbestos exposure-related liabilities for claims arising or existing from activities prior to the transfer of the ownership of the CIPS and CILCO energy centers to Genco and AERG. IPH will be responsible for any asbestos-related claims arising from activities that occur after IPH takes ownership of New AER. Any asbestos-related claims arising solely from activities post transfer of the energy centers from CIPS and CILCO to Genco and AERG, respectively, but prior to IPH taking ownership of New AER, of which there are currently none, will be retained by Ameren. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding Ameren's divestiture of AER. The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of June 30, 2013:
At June 30, 2013, Ameren, Ameren Missouri and Ameren Illinois had liabilities of $16 million, $7 million, and $9 million, respectively, recorded to represent their best estimate of their obligations related to asbestos claims. Ameren Illinois has a tariff rider to recover the costs of IP asbestos-related litigation claims, subject to the following terms: 90% of cash expenditures in excess of the amount included in base electric rates are to be recovered from a trust fund that was established when Ameren acquired IP. At June 30, 2013, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, Ameren Illinois will contribute 90% of the difference to the trust fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider. The rider will permit recovery from customers within IP’s historical service territory. Ameren Illinois Municipal Taxes Ameren Illinois received tax liability notices from the City of O'Fallon, Illinois relating to prior-period electric and natural gas municipal taxes. The city alleges that Ameren Illinois failed to collect prior-period taxes from more than 2,400 accounts primarily in annexed areas for the period 2004 through 2012. In July 2013, the O’Fallon city administrator issued an order stating that Ameren Illinois was liable to the City of O’Fallon for $4 million. Ameren Illinois believes its defenses to the allegations are meritorious and will defend itself vigorously. In August 2013, Ameren Illinois filed an appeal and a stay of the O’Fallon city administrator’s order to the St. Clair County Circuit Court. As of June 30, 2013, Ameren Illinois estimated its obligation at $0.5 million to $4 million. Ameren Illinois recorded a liability of $0.5 million to represent its estimated minimum obligation to the City of O'Fallon, as no other amount within the range was a better estimate. In addition, at the end of 2012, six other cities issued tax liability notices alleging that Ameren Illinois failed to collect prior-period taxes from certain accounts. At this time, it is premature in Ameren Illinois' review of the additional notices received at the end of 2012 to reasonably estimate any likelihood of loss. Illinois Sales and Use Tax Exemptions and Credits In Exelon Corporation v. Department of Revenue, the Illinois Supreme Court decided in 2009 that electricity is tangible personal property for purposes of the Illinois income tax investment credit. In March 2010, the United States Supreme Court refused to hear an appeal of the case, and the decision became final. During the second quarter of 2010, Genco, including EEI, and AERG began claiming Illinois sales and use tax exemptions and credits for purchase transactions related to their generation operations. The primary basis for those claims is that the determination in the Exelon case that electricity is tangible personal property applies to sales and use tax manufacturing exemptions and credits. In November 2011, EEI received a notice of proposed tax liability, documenting the state of Illinois' position that EEI did not qualify for the manufacturing exemption it used during 2010. During the second quarter of 2013, Ameren and the Department of Revenue resolved the tax liabilities for all open periods related to this issue with a payment of $7 million by Genco, including EEI, and AERG to the Illinois Department of Revenue. This charge was recorded within “Loss from Discontinued Operations, Net of Taxes” on Ameren’s consolidated statement of income (loss) in the second quarter of 2013. Medina Valley Asset Sale In February 2012, Ameren completed the sale of the Medina Valley energy center’s net property and plant for cash proceeds of $16 million and an additional $1 million to be paid at the two-year anniversary date of the sale if all terms of the sale agreement were met. Ameren recognized a $10 million pretax gain from this sale. In October 2012, the buyer of the Medina Valley energy center asserted that AER had not met all the terms of the sale agreement. During the first quarter of 2013, Ameren concluded it was no longer probable it would receive the additional $1 million associated with this sale and therefore expensed the receivable amount. |
Derivative Financial Instruments (Offsetting Derivative Assets and Liabilities) (Details) (Commodity Contract [Member], USD $)
In Millions, unless otherwise specified |
Jun. 30, 2013
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Dec. 31, 2012
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Offsetting Assets and Liabilities [Line Items] | ||||||||
Gross Amounts Recognized in the Balance Sheet | $ 57 | [1] | $ 29 | [1] | ||||
Derivative Instruments | 15 | 10 | ||||||
Cash Collateral Received/Posted | [2] | [2] | ||||||
Net Amount | 42 | 19 | ||||||
Gross Amounts Recognized in the Balance Sheet | 183 | [1] | 230 | [1] | ||||
Derivative Instruments | 15 | 10 | ||||||
Cash Collateral Received/Posted | 32 | [2] | 65 | [2] | ||||
Net Amount | 136 | 155 | ||||||
Ameren Missouri [Member]
|
||||||||
Offsetting Assets and Liabilities [Line Items] | ||||||||
Gross Amounts Recognized in the Balance Sheet | 53 | [1] | 28 | [1] | ||||
Derivative Instruments | 13 | 9 | ||||||
Cash Collateral Received/Posted | [2] | [2] | ||||||
Net Amount | 40 | 19 | ||||||
Gross Amounts Recognized in the Balance Sheet | 28 | [1] | 25 | [1] | ||||
Derivative Instruments | 13 | 9 | ||||||
Cash Collateral Received/Posted | 6 | [2] | 7 | [2] | ||||
Net Amount | 9 | 9 | ||||||
Ameren Illinois Company [Member]
|
||||||||
Offsetting Assets and Liabilities [Line Items] | ||||||||
Gross Amounts Recognized in the Balance Sheet | 4 | 1 | ||||||
Derivative Instruments | 2 | 1 | ||||||
Cash Collateral Received/Posted | [2] | [2] | ||||||
Net Amount | 2 | |||||||
Gross Amounts Recognized in the Balance Sheet | 155 | [1] | 205 | [1] | ||||
Derivative Instruments | 2 | 1 | ||||||
Cash Collateral Received/Posted | 26 | [2] | 58 | [2] | ||||
Net Amount | $ 127 | $ 146 | ||||||
|
Consolidated Statement of Comprehensive Income (Loss) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
|
Income from Continuing Operations | $ 106 | $ 162 | $ 162 | $ 201 |
Other Comprehensive Income, Net of Taxes | ||||
Pension and other postretirement benefit plan activity, net of income taxes (benefit) | 10 | 1 | 10 | 1 |
Pension and other postretirement benefit plan activity, tax expense (benefit) | 8 | 0 | 8 | 0 |
Other Comprehensive Income, Net of Taxes | 10 | 1 | 10 | 1 |
Comprehensive Income from Continuing Operations | 116 | 163 | 172 | 202 |
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 1 | 1 | 3 | 3 |
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation | 115 | 162 | 169 | 199 |
Net Income (Loss) from Discontinued Operations | (10) | 48 | (209) | (394) |
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Taxes | (4) | 4 | (11) | 19 |
Comprehensive Income (Loss) from Discontinued Operations | (14) | 52 | (220) | (375) |
Less: Comprehensive Loss from Discontinued Operations Attributable to Noncontrolling Interest | 0 | (2) | 0 | (4) |
Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation | (14) | 54 | (220) | (371) |
Comprehensive Income (Loss) | $ 101 | $ 216 | $ (51) | $ (172) |
Rate And Regulatory Matters
|
6 Months Ended |
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Jun. 30, 2013
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Public Utilities, General Disclosures [Abstract] | |
RATE AND REGULATORY MATTERS | RATE AND REGULATORY MATTERS Below is a summary of updates to significant regulatory proceedings and related lawsuits. See also Note 2 - Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. We are unable to predict the ultimate outcome of these matters, the timing of the final decisions of the various agencies and courts, or the impact on our results of operations, financial position, or liquidity. Missouri FAC Prudence Reviews Missouri law requires the MoPSC to perform prudence reviews of Ameren Missouri's FAC at least every 18 months. In April 2011, the MoPSC issued an order with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. In this order, the MoPSC ruled that Ameren Missouri should have included in the FAC calculation all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda's load caused by a severe ice storm in January 2009. As a result of the order, Ameren Missouri recorded a pretax charge to earnings of $18 million, including $1 million for interest, in 2011 for its obligation to refund to Ameren Missouri's electric customers the earnings associated with these sales previously recognized by Ameren Missouri during the period from March 1, 2009, to September 30, 2009. Ameren Missouri completed its refund to customers in 2012 as directed by the April 2011 MoPSC order. In May 2012, upon appeal by Ameren Missouri, the Cole County Circuit Court reversed the MoPSC's April 2011 order. In June 2012, the MoPSC and a group of large industrial customers filed an appeal of the Cole County Circuit Court's ruling to the Missouri Court of Appeals, Western District. In May 2013, the Missouri Court of Appeals upheld the MoPSC’s April 2011 order and reversed the Cole County Circuit Court’s May 2012 decision. Ameren Missouri determined that it would not appeal the Missouri Court of Appeals’ decision. Ameren Missouri’s FAC calculation for the period from October 1, 2009, to May 31, 2011, excluded all revenues and costs associated with certain long-term partial requirements sales that were made by Ameren Missouri because of the loss of Noranda’s load caused by a severe ice storm in January 2009, similar to the FAC calculation for the period from March 1, 2009, to September 30, 2009. As a result of the Missouri Court of Appeal’s May 2013 decision on the MoPSC’s April 2011 order, Ameren Missouri recorded a pretax charge to earnings of $23 million, including $1 million for interest, in the second quarter of 2013 for its estimated obligation to refund to Ameren Missouri’s electric customers the earnings associated with these sales previously recognized by Ameren Missouri for the period from October 1, 2009, to May 31, 2011. Ameren Missouri recorded the charge to “Operating Revenues - Electric” and the related interest to “Interest Charges” with a corresponding offset to “Current regulatory liabilities.” No similar revenues were excluded from FAC calculations after May 2011. On July 31, 2013, the MoPSC issued an order calculating the refund of these earnings to be $26 million, including $1 million of interest. Ameren Missouri is evaluating its options regarding seeking rehearing or appeal of the MoPSC’s order as it relates to the additional $3 million of refunds, as Ameren Missouri believes it has already refunded $3 million to customers through the FAC. Separately, in July 2011, Ameren Missouri filed a request with the MoPSC for an accounting authority order that would allow Ameren Missouri to defer, as a regulatory asset, fixed costs totaling $36 million that were not recovered from Noranda as a result of the loss of load caused by the severe 2009 ice storm for potential recovery in a future electric rate case. This case remains pending and we cannot predict its outcome. The MoPSC’s FAC prudence review for the period from June 1, 2011, to September 30, 2012, was initiated on March 1, 2013. The MoPSC is expected to issue an order for this prudence review in 2013. 2012 Electric Rate Order In December 2012, the MoPSC issued an order approving an increase for Ameren Missouri in annual revenues for electric service of $260 million. In January 2013, Ameren Missouri appealed the order with respect to the amount of property taxes included in the order to the Missouri Court of Appeals, Western District. In July 2013, Ameren Missouri withdrew its appeal related to the 2012 electric rate order. In February 2013, the MoOPC, MIEC and other parties filed separate appeals to the Missouri Court of Appeals, Western District, relating to the 2012 electric rate order’s treatment of transmission costs in the FAC. The appeals filed by MoOPC, MIEC and other parties were consolidated and are still pending. A decision is expected by the Missouri Court of Appeals, Western District, in 2013. Ameren Missouri cannot predict the ultimate outcome of this appeal, which could adversely impact its results of operations. Illinois IEIMA Under the provisions of the IEIMA, Ameren Illinois’ electric delivery service rates effective in 2013 are subject to an annual revenue requirement reconciliation to its actual 2013 costs. The 2013 revenue requirement reconciliation will be filed with the ICC in 2014. The approved annual revenue requirement reconciliation adjustment will be reflected in customer rates beginning in January 2015. Throughout the year, Ameren Illinois records a regulatory asset or a regulatory liability and a corresponding increase or decrease to operating revenues for any differences between the revenue requirement in effect for that year and its best estimate of the probable increase or decrease in the revenue requirement expected to ultimately be approved by the ICC based on that year's actual costs incurred. As of June 30, 2013, Ameren Illinois recorded a $33 million regulatory asset to reflect the year-to-date portion of its expected 2013 revenue requirement reconciliation adjustment. As of June 30, 2013 and December 31, 2012, Ameren Illinois recorded a regulatory liability of $57 million and $55 million, respectively, to reflect its expected 2012 revenue requirement reconciliation adjustment, with interest, which will be refunded to customers in 2014, pending ICC approval as discussed below. In May 2013, Illinois enacted into law certain amendments to the IEIMA that modify its implementation. The law clarified that the IEIMA requires that the year-end rate base be used to calculate the revenue requirement reconciliation and that the interest applied to the revenue requirement reconciliation and return on equity collar adjustments be equal to a company’s weighted-average return calculated under the formula rate. In September 2012, the ICC issued an order in Ameren Illinois’ initial filing under the IEIMA’s performance-based formula rate framework. In October 2012, Ameren Illinois filed an appeal of the ICC’s initial filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. In December 2012, the ICC issued an order in Ameren Illinois’ update filing approving an Ameren Illinois electric delivery service revenue requirement of $765 million, based on 2011 recoverable costs and expected net plant additions for 2012. The delivery service rates became effective on January 1, 2013, and will remain effective through the end of 2013. These rates are subject to a reconciliation to actual 2013 costs, which will be filed with the ICC in 2014. In January 2013, Ameren Illinois filed an appeal of the ICC's update filing order to the Appellate Court of the Fourth District of Illinois. A decision by the appellate court is expected in 2013. Many of the issues that were the subject of Ameren Illinois’ appeals of the September 2012 order and the December 2012 order were resolved with the enactment of the May 2013 amendments to the IEIMA referred to above; however, disputes regarding the treatment of deferred taxes and vacation obligations as well as the calculation of Ameren Illinois’ capital structure remain. If the appellate court rules in favor of Ameren Illinois’ positions on these disputed items, the electric delivery service revenue requirement included in the December 2012 order would have increased by $11 million. Ameren Illinois anticipates that any changes originating from these appeals would be applied prospectively through the IEIMA formula rate process. In April 2013, Ameren Illinois filed its annual electric delivery service formula rate update with the ICC based on 2012 recoverable costs and expected net plant additions for 2013. In July 2013, the update filing was revised based on the enactment of the May 2013 amendments to the IEIMA referred to above. Pending ICC approval, the revised update filing, as filed by Ameren Illinois, will result in an aggregate $38 million decrease in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2014. The update filing includes a proposed refund to customers of the 2012 revenue requirement reconciliation of $56 million, which includes an estimate for interest through the end of 2014. Ameren Illinois’ balance sheet as of June 30, 2013, includes a $57 million regulatory liability relating to this 2012 revenue requirement reconciliation, which will continue to accrue interest through 2014 and is expected to increase to $63 million with interest accrued through 2014. In the update filing, the proposed refund is partially offset by an annual revenue requirement increase of $18 million primarily due to increased recoverable costs over 2011 levels. Ameren Illinois’ filing reflects an electric delivery service revenue requirement of $783 million, before consideration of the 2012 revenue requirement reconciliation refund. In July 2013, the ICC staff submitted its calculation of the revenue requirement included in Ameren Illinois’ update filing. The ICC staff recommended an aggregate $60 million decrease in Ameren Illinois’ electric delivery service revenue requirement. The calculation includes a refund to customers of the 2012 revenue requirement reconciliation of $68 million, which includes an estimate for interest through the end of 2014. However, this refund is partially offset by an annual revenue requirement increase of $8 million primarily due to increased recoverable costs over 2011 levels. The ICC staff’s filing reflects an electric delivery service revenue requirement of $772 million, before consideration of the 2012 revenue requirement reconciliation refund. An ICC decision with respect to the July 2013 revised update filing is expected in December 2013 and will establish rates for all of 2014. In December 2013, Ameren Illinois will record an adjustment to its regulatory liability for its 2012 revenue requirement reconciliation refund based on the ICC’s order. 2013 Natural Gas Delivery Service Rate Case In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service. The current request, as revised in July 2013, seeks to increase annual revenues for natural gas delivery service by $50 million. The revised natural gas rate increase request was based on a 10.4% return on equity, a capital structure composed of 51.8% common equity, and a rate base of $1.1 billion. In an attempt to reduce regulatory lag, Ameren Illinois is using a future test year of 2014 in this proceeding. Also in its filing, Ameren Illinois is requesting an increase in the percentage of costs to be recovered through a fixed non-volumetric customer charge from 80% to 85% for all residential customers and most commercial customers. Ameren Illinois is also seeking recovery of capital costs to enable residential customers the option to choose their natural gas commodity supplier, although that option currently does not exist for these customers. In August 2013, the ICC staff responded to Ameren Illinois' revised request and recommended a net increase in revenues for natural gas delivery service of $24 million, based on an 8.8% return on equity, a capital structure composed of 50.4% common equity, and a rate base of $1.1 billion. A decision by the ICC in this proceeding is required by December 2013. Ameren Illinois cannot predict the level of any natural gas delivery service rate changes the ICC may approve or whether any rate changes that may eventually be approved will be sufficient to enable Ameren Illinois to recover its costs and earn a reasonable return on its investments when the rate changes go into effect. Natural Gas Consumer, Safety and Reliability Act In July 2013, Illinois enacted a law called the Natural Gas Consumer, Safety and Reliability Act that enables Illinois natural gas utilities to accelerate modernization of the state’s natural gas infrastructure and provide additional ICC oversight of natural gas utility performance. Utilities that participate may implement rate surcharges for certain infrastructure investments made between rate cases. The legislation allows natural gas utilities the option to file, and requires the ICC to approve, a rate rider mechanism to provide for recovery of costs associated with certain categories of investment to improve the safety and reliability of the state’s natural gas infrastructure. The legislation also requires natural gas utilities that choose to participate in this regulatory framework to file annual plans with the ICC and report on progress in achieving performance improvements. The law is effective immediately. Ameren Illinois is currently evaluating when to participate in this regulatory framework. ATXI Transmission Project ATXI’s Illinois Rivers project is a MISO-approved project to build a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. In 2012, ATXI made a filing with the ICC requesting a certificate of public convenience and necessity, and project approval. In July 2013, Illinois administrative law judges issued a proposed order finding that the project is necessary to address transmission and reliability needs in an efficient and equitable manner and that the project will benefit the development of a competitive electricity market. The administrative law judges also agreed that ATXI is capable of constructing and managing the project as well as financing it. The administrative law judges recommended approval of seven of a total of nine portions of the route. For the remaining two portions, the administrative law judges concluded that a determination could not be made as to whether these are the least cost alternatives and identified concerns around the placement of certain substations. ATXI has filed a response to the administrative law judges’ proposed order in a subsequent filing with the ICC. An order from the ICC is expected in August 2013. Federal 2011 Wholesale Distribution Rate Case In January 2011, Ameren Illinois filed a request with FERC to increase its annual revenues for electric delivery service for its wholesale customers. These wholesale distribution revenues are treated as a deduction from Ameren Illinois’ revenue requirement in retail rate filings with the ICC. In March 2011, FERC issued an order authorizing the proposed rates to take effect, subject to refund when the final rates are determined. Ameren Illinois has reached an agreement with four of its nine wholesale customers. The impasse with the remaining five wholesale customers has resulted in FERC litigation. In November 2012, a FERC administrative law judge issued an initial decision, which is now pending before FERC. The timing of a FERC decision is uncertain. Based on the administrative law judge's initial decision, Ameren and Ameren Illinois each has included on its balance sheet in “Current regulatory liabilities” an estimate of $11 million and $8 million as of June 30, 2013, and December 31, 2012, respectively, for the refund due to wholesale customers relating to billings for the period from March 2011 through June 2013. Ameren Illinois Electric Transmission Rate Refund In July 2012, FERC issued an order with respect to Ameren Illinois' accounting for the Ameren Illinois Merger. As part of this order, FERC concluded that Ameren Illinois improperly included acquisition premiums, particularly goodwill, in determining its common equity used in its electric transmission formula rate, thereby inappropriately recovering a higher return on rate base from its electric transmission customers. The order required Ameren Illinois to make refunds to customers for such improperly included amounts. In August 2012, Ameren Illinois filed a request for rehearing of this order. It is unknown when FERC will rule on Ameren's rehearing request, as it is under no deadline to do so. Ameren Illinois submitted a refund report in November 2012 and concluded that no refund was warranted. Several wholesale customers filed a protest with FERC regarding Ameren's conclusion that no refund is warranted. In June 2013, FERC issued an order that rejected Ameren Illinois’ November 2012 refund report and provided guidance as to the filing of a new refund report. In July 2013, Ameren Illinois filed a revised refund report based on the guidance provided in the June 2013 order, and also filed a request for rehearing of that order. Ameren Illinois’ July 2013 refund report again concluded that no refund was warranted. Ameren Illinois estimates the maximum pretax charge to earnings for this contingency would be between $10 million and $15 million, before interest charges. If Ameren Illinois were to determine that a refund to its electric transmission customers is probable, a charge to earnings would be recorded for the refund in the period in which that determination was made and the amount could be estimated. Combined Construction and Operating License In 2008, Ameren Missouri filed an application with the NRC for a COL for a new nuclear unit at Ameren Missouri's existing Callaway County, Missouri, energy center site. In 2009, Ameren Missouri suspended its efforts to build a new nuclear unit at its existing Missouri nuclear energy center site, and the NRC suspended review of the COL application. In March 2012, the DOE announced the availability of investment funds for the design, engineering, manufacturing, and sale of American-made small modular nuclear reactors. In April 2012, Ameren Missouri entered into an agreement with Westinghouse to exclusively support Westinghouse's application for the first installment of DOE's small modular nuclear reactor investment funds. The DOE investment funding is intended to support engineering and design certifications and a COL for up to two small modular reactor designs over five years. In November 2012, the DOE awarded the first installment of investment funds for only one small modular reactor design, which was not the Westinghouse design, but also stated that a second installment of investment funds would be awarded during 2013. Westinghouse continues to seek funds from the DOE’s first installment of investment funds. Westinghouse submitted an application to the DOE in June 2013 for the second installment of investment funds. If Westinghouse is awarded DOE's small modular reactor investment funds in this second installment round of funding, Ameren Missouri may pursue a COL from the NRC for a Westinghouse small modular reactor or multiple reactors at its Callaway energy center site. A COL is issued by the NRC to permit construction and operation of a nuclear energy center at a specific site in accordance with established laws and regulations. Obtaining a COL from the NRC would not obligate Ameren Missouri to build a small modular reactor at the Callaway site; however, it would preserve the option to move forward in a timely fashion should conditions be right to build a small modular reactor in the future. A COL is valid for at least 40 years. Ameren Missouri estimates the total cost to obtain the small modular reactor COL will be in the range of $80 million to $100 million. As of June 30, 2013, Ameren Missouri has capitalized investments for the development of a new nuclear energy center of $69 million. Ameren Missouri expects its incremental investment to obtain the small modular reactor COL to be minimal. As discussed above, the DOE investment funds could help support the completion of a COL application. If the DOE does not select Westinghouse's applications for small modular reactor investment funds, Ameren Missouri is not obligated to pursue a COL for the Westinghouse small modular reactor design and may terminate its agreement with Westinghouse regarding the first installment of DOE investment funds. All of Ameren Missouri's costs incurred to license additional nuclear generation at the Callaway site will remain capitalized while management pursues options to maximize the value of its investment. If efforts are permanently abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination is made. |
Summary Of Significant Accounting Policies (Tables)
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Jun. 30, 2013
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Accounting Policies [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary Of Nonvested Shares Related To Long-Term Incentive Plan | A summary of nonvested performance share units at June 30, 2013, and changes during the six months ended June 30, 2013, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) are presented below:
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Schedule Of Amortization Expense Based On Usage Of Renewable Energy Credits And Emission Allowances | The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri, and Ameren Illinois, during the three and six months ended June 30, 2013, and 2012.
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Schedule of Excise Taxes | The following table presents excise taxes recorded in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” for the three and six months ended June 30, 2013, and 2012:
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Equity Changes Attributable To Noncontrolling Interest | A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three and six months ended June 30, 2013, and 2012, is shown below:
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Commitments And Contingencies (Callaway Energy Center) (Detail) (USD $)
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6 Months Ended | 6 Months Ended | 0 Months Ended | 6 Months Ended | |||||||||||||||||||||||
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Jun. 30, 2013
Week
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Jun. 30, 2013
Replacement Power - Nuclear Electric Insurance Ltd [Member]
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Jun. 30, 2013
Replacement Power - Energy Risk Assurance Company [Member]
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Jun. 30, 2013
Public Liability And Nuclear Worker Liability - American Nuclear Insurers [Member]
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Jun. 30, 2013
Public Liability And Nuclear Worker Liability - Pool Participation [Member]
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Jun. 30, 2013
Property Damage - Nuclear Electric Insurance Ltd [Member]
|
Jul. 02, 2013
Property Damage - Nuclear Electric Insurance Ltd [Member]
Subsequent Event [Member]
|
Jun. 30, 2013
Property Damage European Mutual Association for Nuclear Insurance [Member]
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Commitments And Contingencies [Line Items] | |||||||||||||||||||||||||||
Maximum Coverages | $ 12,594,000,000 | [1] | $ 490,000,000 | [2] | $ 64,000,000 | [3] | $ 375,000,000 | $ 12,219,000,000 | [4] | $ 2,750,000,000 | [5] | ||||||||||||||||
Maximum Assessments for Single Incidents | 118,000,000 | 9,000,000 | [6] | 118,000,000 | [7] | 23,000,000 | |||||||||||||||||||||
Threshold for which a retrospective assessment for a covered loss is necessary | 375,000,000 | ||||||||||||||||||||||||||
Annual payment in the event of an incident at any licensed commercial reactor | 17,500,000.0 | ||||||||||||||||||||||||||
Aggregate maximum assessment per incident under Price-Anderson liability provisions of Atomic Energy Act | 118,000,000 | ||||||||||||||||||||||||||
Maximum annual payment in calendar year per reactor incident under Price Andersen Liability Provisions of Atomic Energy Act | 17,500,000.0 | ||||||||||||||||||||||||||
Amount of primary property liability coverage | 500,000,000 | 500,000,000 | 500,000,000 | ||||||||||||||||||||||||
Amount of coverage in excess of primary property liability coverage | 2,250,000,000.00 | ||||||||||||||||||||||||||
Losses in excess of primary coverage | 500,000,000 | ||||||||||||||||||||||||||
Sub-limit for non-nuclear events | 1,700,000,000 | 1,500,000,000.0 | 200,000,000 | ||||||||||||||||||||||||
Amount of weekly indemnity coverage commencing eight weeks after power outage | 4,500,000.0 | ||||||||||||||||||||||||||
Number of weeks of coverage after the first eight weeks of an outage | 52 | ||||||||||||||||||||||||||
Amount of additional weekly indemnity coverage commencing after initial indemnity coverage | 3,600,000 | ||||||||||||||||||||||||||
Number of additional weeks after initial indemnity coverage for power outage, minimum | 71 | ||||||||||||||||||||||||||
Amount of weekly indemnity coverage thereafter not exceeding policy limit | 490,000,000 | 3,600,000 | |||||||||||||||||||||||||
Sub-limit of for non-nuclear events | 327,600,000 | ||||||||||||||||||||||||||
Amount of secondary weekly indemnity coverage for prolonged nuclear plant outage in excess of primary indemnity coverage | 900,000 | ||||||||||||||||||||||||||
Inflationary adjustment prescribed by most recent Price-Anderson Act renewal, in years | 5 years | ||||||||||||||||||||||||||
Aggregate nuclear power industry insurance policy limit for losses from terrorist attacks within twelve month period | $ 3,240,000,000 | ||||||||||||||||||||||||||
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Derivative Financial Instruments (Potential Loss On Counterparty Exposures) (Detail) (USD $)
In Millions, unless otherwise specified |
Jun. 30, 2013
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Dec. 31, 2012
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | $ 10 | $ 15 |
Ameren Missouri [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 10 | 15 |
Commodity Marketing Companies [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 1 | 1 |
Commodity Marketing Companies [Member] | Ameren Missouri [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 1 | 1 |
Electric Utilities [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 4 | 1 |
Electric Utilities [Member] | Ameren Missouri [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 4 | 1 |
Financial Companies [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 2 | 10 |
Financial Companies [Member] | Ameren Missouri [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 2 | 10 |
Municipalities/Cooperatives [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | 3 | 3 |
Municipalities/Cooperatives [Member] | Ameren Missouri [Member]
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Concentration Risk [Line Items] | ||
Potential loss on counterparty exposures related to derivative contracts | $ 3 | $ 3 |
Callaway Energy Center
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6 Months Ended |
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Jun. 30, 2013
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Nuclear Waste Matters [Abstract] | |
CALLAWAY ENERGY CENTER | CALLAWAY ENERGY CENTER Under the NWPA, the DOE is responsible for disposing of spent nuclear fuel from the Callaway energy center and other commercial nuclear energy centers. Under the NWPA, Ameren Missouri and other companies that own and operate those energy centers are responsible for paying the disposal costs. The NWPA established the fee that these companies pay the federal government for disposing of the spent nuclear fuel at one mill, or one-tenth of one cent, for each kilowatthour generated by those plants and sold. The NWPA also requires the DOE to review the nuclear waste fee against the cost of the nuclear waste disposal program and to propose to the United States Congress any fee adjustment necessary to offset the costs of the program. As required by the NWPA, Ameren and other companies have entered into standard contracts with the DOE, which is the agency responsible for implementing the NWPA. Consistent with the NWPA and its standard contract, Ameren Missouri collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway energy center. Both the NWPA and the standard contract stated that the federal government would begin to dispose of spent nuclear fuel by 1998, however, no federal storage facility currently exists. Ameren Missouri has sufficient installed capacity at its Callaway energy center to store the spent nuclear fuel generated at Callaway through 2020 and has the capability for additional storage capacity for spent nuclear fuel generated through the end of the energy center’s current licensed life. Until January 2009, the DOE program provided for spent nuclear fuel disposal to take place at a geologic repository to be constructed at Yucca Mountain, Nevada. In January 2009, the federal government announced that a repository at Yucca Mountain was unworkable and took steps to terminate the Yucca Mountain program, while acknowledging the federal government’s continuing obligation to dispose of companies’ spent nuclear fuel. In January 2012, an advisory commission established by the DOE issued its report of recommendations for the storage and disposal of spent nuclear fuel. The recommendations covered topics such as the approach to siting future nuclear waste management facilities, the transport and storage of spent fuel and high-level waste, options for waste disposal, institutional arrangements for managing spent nuclear fuel and high-level wastes, and changes needed in the handling of nuclear waste fees and of the Nuclear Waste Fund. In January 2013, the DOE issued its plan for the management and disposal of spent nuclear fuel in response to the recommendation contained in the advisory commission's report. The DOE's plan calls for a pilot interim storage facility to begin operation with an initial focus on accepting spent nuclear fuel from shutdown reactor sites by 2021. By 2025, a larger interim storage facility would be available and would be co-located with the pilot facility. The plan also proposes to site a permanent geological repository to begin operation by 2048. The DOE's delay in carrying out its obligation to dispose of spent nuclear fuel from the Callaway energy center is not expected to adversely affect the continued operation of the energy center. As a result of the DOE's failure to begin to dispose of the spent nuclear fuel from nuclear energy centers and fulfill its contractual obligations, Ameren Missouri and other nuclear energy center owners have sued the DOE to recover costs incurred for ongoing storage of their spent fuel. Ameren Missouri filed a breach of contract lawsuit to recover costs that it incurred through 2009. This amount included the cost of reracking the Callaway energy center’s spent fuel pool, as well as certain NRC fees, and Missouri ad valorem taxes that Ameren Missouri would not have incurred had DOE performed its contractual obligations. In June 2011, the parties reached a settlement that included an annual reimbursement of Ameren Missouri’s spent fuel storage and related costs through at least 2013. In March 2013, Ameren Missouri submitted its 2012 costs to the DOE for reimbursement under the settlement agreement. Ameren Missouri expects to receive the 2012 cost reimbursement of $6 million during the third quarter of 2013. These costs were recorded in “Miscellaneous accounts and notes receivable” on Ameren’s and Ameren Missouri’s balance sheets. In December 2011, Ameren Missouri filed a license extension application with the NRC to extend its Callaway energy center's operating license from 2024 to 2044. There is no deadline by which the NRC must act on this application. Among the rules that the NRC has historically relied upon in approving license extensions are rules dealing with the storage of spent nuclear fuel at the reactor site and with the NRC's confidence that permanent disposal of spent nuclear fuel will be available when needed. In a June 2012 decision, the United States Court of Appeals for the District of Columbia Circuit vacated these rules and remanded the case to the NRC, holding that the NRC's obligations under the National Environmental Policy Act required a more thorough environmental analysis in support of the NRC's waste confidence decision. In June 2012, a number of groups petitioned the NRC to suspend final licensing decisions in certain NRC licensing proceedings, including the Callaway energy center license extension, until the NRC completed its proceedings on the vacated rules. In August 2012, the NRC stated that it would not issue licenses dependent on the vacated rules until it appropriately addressed the court's remand. In September 2012, the NRC directed its staff to issue, within two years, a new waste confidence final environmental impact statement (EIS) and a final rule to address the court's ruling. The newly created Waste Confidence Directorate within NRC now oversees the drafting of a new waste confidence EIS and rule, and its schedule presently provides for issuance of the final EIS and final rule by no later than September 2014. If the Callaway energy center's license is extended, additional spent fuel storage will be required. Ameren Missouri plans to install a dry spent fuel storage facility at its Callaway energy center and intends to begin transferring spent fuel assemblies to this facility by 2016. Electric utility rates charged to customers provide for the recovery of the Callaway energy center's decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the nuclear center, ending with the expiration of the energy center's current operating license in 2024. It is assumed that the Callaway energy center site will be decommissioned through the immediate dismantlement method and removed from service. Ameren and Ameren Missouri have recorded an ARO for the Callaway energy center decommissioning costs at fair value, which represents the present value of estimated future cash outflows. Decommissioning costs are included in the costs of service used to establish electric rates for Ameren Missouri's customers. These costs amounted to $7 million in each of the years 2012, 2011, and 2010. Every three years, the MoPSC requires Ameren Missouri to file an updated cost study and funding analysis for decommissioning its Callaway energy center. Electric rates may be adjusted at such times to reflect changed estimates. If Ameren Missouri's operating license extension application is approved by the NRC, a revised funding analysis will be prepared and the rates charged to customers will be adjusted accordingly to reflect the operating license extension at the time of the next triennial cost study and funding analysis is approved by the MoPSC. Amounts collected from customers are deposited in an external trust fund to provide for the Callaway energy center's decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for Ameren Missouri's Callaway energy center is reported as "Nuclear decommissioning trust fund" in Ameren's and Ameren Missouri's balance sheets. This amount is legally restricted and may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund, with an offsetting adjustment to the related regulatory liability. See Note 3 - Rate and Regulatory Matters for additional information related to the Callaway energy center. |
Long-Term Debt And Equity Financings (Schedule Of Covered Ratio) (Detail) (USD $)
In Millions, unless otherwise specified |
6 Months Ended | |||||||||
---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
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Ameren Missouri [Member]
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Debt Instrument [Line Items] | ||||||||||
Bonds Issuable | $ 3,633 | [1] | ||||||||
Preferred Stock Issuable | 2,118 | |||||||||
Retired bond capacity | 485 | |||||||||
Ameren Missouri [Member] | Actual Ratio [Member]
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Debt Instrument [Line Items] | ||||||||||
Restricted payment interest coverage ratio, Actual | 4.4 | |||||||||
Dividend Coverage Ratio | 110.9 | |||||||||
Ameren Illinois Company [Member]
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Debt Instrument [Line Items] | ||||||||||
Bonds Issuable | 3,581 | [1],[2] | ||||||||
Preferred Stock Issuable | 203 | |||||||||
Retired bond capacity | $ 645 | |||||||||
Ameren Illinois Company [Member] | Actual Ratio [Member]
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Debt Instrument [Line Items] | ||||||||||
Restricted payment interest coverage ratio, Actual | 7.3 | |||||||||
Dividend Coverage Ratio | 2.7 | |||||||||
Minimum [Member] | Ameren Missouri [Member] | Minimum Required Ratio [Member]
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Debt Instrument [Line Items] | ||||||||||
Restricted payment interest coverage ratio, Actual | 2.0 | [3] | ||||||||
Dividend Coverage Ratio | 2.5 | [4] | ||||||||
Minimum [Member] | Ameren Illinois Company [Member] | Minimum Required Ratio [Member]
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Debt Instrument [Line Items] | ||||||||||
Restricted payment interest coverage ratio, Actual | 2.0 | [3] | ||||||||
Dividend Coverage Ratio | 1.5 | [4] | ||||||||
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Derivative Financial Instruments (Derivative Instruments With Credit Risk-Related Contingent Features) (Detail) (USD $)
In Millions, unless otherwise specified |
Jun. 30, 2013
|
Dec. 31, 2012
|
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---|---|---|---|---|---|---|---|---|
Derivative [Line Items] | ||||||||
Aggregate Fair Value of Derivative Liabilities | $ 192 | [1] | $ 226 | [1] | ||||
Cash Collateral Posted | 27 | 61 | ||||||
Potential Aggregate Amount of Additional Collateral Required | 127 | [2] | 155 | [2] | ||||
Ameren Missouri [Member]
|
||||||||
Derivative [Line Items] | ||||||||
Aggregate Fair Value of Derivative Liabilities | 76 | [1] | 78 | [1] | ||||
Cash Collateral Posted | 1 | 3 | ||||||
Potential Aggregate Amount of Additional Collateral Required | 45 | [2] | 71 | [2] | ||||
Ameren Illinois Company [Member]
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Derivative [Line Items] | ||||||||
Aggregate Fair Value of Derivative Liabilities | 116 | [1] | 148 | [1] | ||||
Cash Collateral Posted | 26 | 58 | ||||||
Potential Aggregate Amount of Additional Collateral Required | $ 82 | [2] | $ 84 | [2] | ||||
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Summary Of Significant Accounting Policies (Equity Changes Attributable To Noncontrolling Interest) (Detail) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
Electric Energy, Inc [Member]
|
Dec. 31, 2012
Electric Energy, Inc [Member]
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Stockholders' Equity Attributable to Noncontrolling Interest [Roll Forward] | ||||||||||||
Noncontrolling interest, beginning of period | $ 151 | [1] | $ 147 | [1] | $ 151 | [1] | $ 149 | |||||
Net income from continuing operations attributable to noncontrolling interests | 1 | 1 | 3 | 3 | ||||||||
Net income (loss) from discontinued operations attributable to noncontrolling interests | (2) | (4) | ||||||||||
Dividends paid to noncontrolling interest holders | (1) | (1) | (3) | (3) | ||||||||
Noncontrolling interest, end of period | $ 151 | [1] | $ 145 | [1] | $ 151 | [1] | $ 145 | [1] | ||||
Percentage of EEI not owned by Ameren | 20.00% | 20.00% | ||||||||||
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Other Income and Expenses (Tables)
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6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Other Nonoperating Income (Expense) [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Income And Expenses | The following table presents the components of “Other Income and Expenses” in the Ameren Companies’ statements of income (loss) for the three and six months ended June 30, 2013, and 2012:
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Long-Term Debt And Equity Financings (Tables)
|
6 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Long-Term Debt And Equity Financings [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule Of Coverage Ratios | Indenture Provisions and Other Covenants Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable as of June 30, 2013, at an assumed annual interest rate of 6% and dividend rate of 7%.
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Short-Term Debt And Liquidity (Narrative) (Detail) (USD $)
|
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
|
Line of Credit Facility [Line Items] | ||||
Commercial paper outstanding | ||||
Commercial Paper [Member]
|
||||
Line of Credit Facility [Line Items] | ||||
Commercial paper outstanding | 25,000,000 | 25,000,000 | ||
Average daily commercial paper borrowings outstanding | 13,000,000 | 72,000,000 | ||
Weighted average interest rate | 0.54% | 0.94% | 0.54% | 0.94% |
Peak short-term borrowings | 78,000,000 | 229,000,000 | ||
Peak short-term borrowings interest rate | 0.85% | 1.25% | ||
Utilities [Member]
|
||||
Line of Credit Facility [Line Items] | ||||
Short Term Debt, Weighted Average Interest Rate During Period | 0.07% | 0.14% | 0.09% | 0.12% |
Non State Regulated Subsidiaries [Member]
|
||||
Line of Credit Facility [Line Items] | ||||
Short Term Debt, Weighted Average Interest Rate During Period | 0.29% | 0.64% | 0.26% | 0.70% |
Credit Agreements 2012 [Member]
|
||||
Line of Credit Facility [Line Items] | ||||
Line of credit facility, maximum borrowing capacity | $ 2,060,000,000 | $ 2,060,000,000 | ||
Actual debt-to-capital ratio percentage | 0.52 | 0.52 | ||
Minimum ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date | 2.0 to 1 | |||
Covenant terms, ratio of consolidated operational funds to consolidated interest expense, minimum | 2.0 | |||
Current ratio of consolidated funds from operations plus interest expense to consolidated interest expense as of balance sheet date | 4.9 to 1.0 | |||
Covenant compliance, ratio of consolidated operational funds to consolidated interest expense | 4.9 | |||
Credit Agreements 2012 [Member] | Maximum [Member]
|
||||
Line of Credit Facility [Line Items] | ||||
Actual debt-to-capital ratio percentage | 0.65 | 0.65 | ||
Credit Agreements 2012 [Member] | Ameren Missouri [Member]
|
||||
Line of Credit Facility [Line Items] | ||||
Actual debt-to-capital ratio percentage | 0.48 | 0.48 | ||
Credit Agreements 2012 [Member] | Ameren Illinois Company [Member]
|
||||
Line of Credit Facility [Line Items] | ||||
Actual debt-to-capital ratio percentage | 0.42 | 0.42 |
Summary Of Significant Accounting Policies (Narrative) (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified |
3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 6 Months Ended | 1 Months Ended | 6 Months Ended | 0 Months Ended | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2012
|
Jun. 30, 2012
|
Mar. 31, 2012
|
Jun. 30, 2013
|
Dec. 31, 2012
|
Sep. 30, 2012
Ameren Missouri [Member]
|
Jun. 30, 2012
Ameren Missouri [Member]
|
Mar. 31, 2012
Ameren Missouri [Member]
|
Jun. 30, 2013
Ameren Missouri [Member]
|
Dec. 31, 2012
Ameren Missouri [Member]
|
Jun. 30, 2013
Ameren Illinois Company [Member]
|
Jun. 30, 2013
Electric Energy, Inc [Member]
|
Dec. 31, 2012
Electric Energy, Inc [Member]
|
Jan. 31, 2013
Performance Shares [Member]
|
Jun. 30, 2013
Performance Shares [Member]
|
Mar. 14, 2013
Elgin, Gibson City and Grand Tower Energy Centers [Member]
Ameren Energy Generating Company [Member]
|
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Basis Of Presentation And Significant Accounting Policies [Line Items] | |||||||||||||||||||
Ownership interest | 80.00% | ||||||||||||||||||
Initial payment received | $ 100 | ||||||||||||||||||
Identified immaterial errors | 49 | 26 | 14 | 49 | 26 | 14 | |||||||||||||
Fair value of each share unit, per share | $ 31.19 | $ 31.19 | [1] | ||||||||||||||||
Closing common share price | $ 30.72 | ||||||||||||||||||
Performance period | 3 years | ||||||||||||||||||
Three-year risk-free rate | 0.36% | ||||||||||||||||||
Volatility rate, minimum | 12.00% | ||||||||||||||||||
Volatility rate, maximum | 21.00% | ||||||||||||||||||
Book value or renewable energy credits | 18 | 14 | 18 | 14 | |||||||||||||||
Unrecognized tax benefits | 193 | 127 | 4 | ||||||||||||||||
Unrecognized tax benefits (detriments) that would impact effective tax rate | 49 | 1 | (1) | ||||||||||||||||
Increase in unrecognized tax benefits that would impact effective tax rate | 48 | ||||||||||||||||||
Estimated unrecognized tax decreases resulting from settlements with taxing authorities | $ 126 | $ 110 | $ 5 | ||||||||||||||||
Percentage of EEI not owned by Ameren | 20.00% | 20.00% | |||||||||||||||||
|
Divestiture Transactions and Discontinued Operations (Components of Discontinued Operations in Consolidated Statement of Income) (Details) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
New Ameren Energy Resources Company, LLC [Member]
|
Mar. 31, 2013
New Ameren Energy Resources Company, LLC [Member]
|
Jun. 30, 2013
New Ameren Energy Resources Company, LLC [Member]
|
Jun. 30, 2012
Duck Creek Energy Center [Member]
New Ameren Energy Resources Company, LLC [Member]
|
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Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||||||||||
Operating revenues | $ 303 | $ 258 | $ 567 | $ 504 | ||||||||||
Operating expenses | (310) | (238) | (725) | [1] | (1,064) | [2] | ||||||||
Operating income (loss) | (7) | 20 | (158) | (560) | ||||||||||
Other income (loss) | 1 | (1) | 0 | |||||||||||
Interest charges | (11) | (14) | (22) | (29) | ||||||||||
Income (loss) before income taxes | (17) | 6 | (181) | (589) | ||||||||||
Income tax (expense) benefit | 7 | 42 | (28) | 195 | ||||||||||
Income (Loss) from discontinued operations, net of taxes | (10) | 48 | (209) | (394) | ||||||||||
Impairment of Long-Lived Assets to be Disposed of | $ 13 | $ 155 | $ 168 | $ 628 | ||||||||||
|
Other Income and Expenses (Detail) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
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Other Nonoperating Income (Expense) [Line Items] | ||||||||||||
Allowance for equity funds used during construction | $ 8 | [1] | $ 8 | [1] | $ 16 | [1] | $ 17 | [1] | ||||
Interest income on industrial development revenue bonds | 7 | [1] | 7 | [1] | 14 | [1] | 14 | [1] | ||||
Interest and dividend income | 1 | [1] | 4 | [1] | 1 | [1] | 4 | [1] | ||||
Other | 0 | [1] | 0 | [1] | 0 | [1] | 1 | [1] | ||||
Total miscellaneous income | 16 | [1] | 19 | [1] | 31 | [1] | 36 | [1] | ||||
Donations | 1.0 | [1] | 3.0 | [1] | 5.0 | [1] | 15.0 | [1],[2] | ||||
Other | 4 | [1] | 4 | [1] | 8 | [1] | 7 | [1] | ||||
Total miscellaneous expense | 5 | [1] | 7 | [1] | 13 | [1] | 22 | [1] | ||||
Ameren Missouri [Member]
|
||||||||||||
Other Nonoperating Income (Expense) [Line Items] | ||||||||||||
Allowance for equity funds used during construction | 7 | 7 | 14 | 15 | ||||||||
Interest income on industrial development revenue bonds | 7 | 7 | 14 | 14 | ||||||||
Interest and dividend income | 0 | 4 | 0 | 4 | ||||||||
Total miscellaneous income | 14 | 18 | 28 | 33 | ||||||||
Donations | 1.0 | 3.0 | 3.0 | 5.0 | ||||||||
Other | 2 | 1 | 5 | 2 | ||||||||
Total miscellaneous expense | 3 | 4 | 8 | 7 | ||||||||
Ameren Illinois [Member]
|
||||||||||||
Other Nonoperating Income (Expense) [Line Items] | ||||||||||||
Allowance for equity funds used during construction | 1 | 1 | 2 | 2 | ||||||||
Interest and dividend income | 1 | 0 | 1 | 0 | ||||||||
Other | 0 | 1 | 0 | 1 | ||||||||
Total miscellaneous income | 2 | 2 | 3 | 3 | ||||||||
Donations | 0 | 0 | 3.0 | 10.0 | [2] | |||||||
Other | 1 | 2 | 1 | 3 | ||||||||
Total miscellaneous expense | 1 | 2 | 4 | 13 | ||||||||
Ameren Illinois [Member] | One-Time Donation [Member] | Illinois Science And Energy Innovation Trust [Member]
|
||||||||||||
Other Nonoperating Income (Expense) [Line Items] | ||||||||||||
Donations | $ 7.5 | |||||||||||
|
Commitments And Contingencies (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Commitments and Contingencies Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Insurance Coverage at Callaway Energy Center | The following table presents insurance coverage at Ameren Missouri’s Callaway energy center at June 30, 2013. The property coverage and the nuclear liability coverage must be renewed on April 1 and January 1, respectively, of each year.
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Schedule of Estimated Capital Costs to Comply With Existing and Known Emissions Related Regulations | Continuing Operations:
Discontinued Operations:
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Schedule of Estimated Obligations for Manufactured Gas Plant Remediation | The following table presents, as of June 30, 2013, the estimated obligation to complete the remediation of these former MGP sites.
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Schedule of Asbestors-Related Litigation Pending Lawsuits | The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of June 30, 2013:
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Fair Value Measurements (Schedule Of Carrying Amounts And Estimated Fair Values Of Long-Term Debt And Preferred Stock) (Detail) (USD $)
In Millions, unless otherwise specified |
Jun. 30, 2013
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Dec. 31, 2012
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Fair Value [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||||
Long-term debt (including current portion) | $ 6,864 | [1],[2] | $ 7,110 | [1],[2] | ||||
Preferred stock | 124 | [1],[2] | 123 | [1],[2] | ||||
Fair Value [Member] | Ameren Missouri [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||||
Long-term debt (including current portion) | 4,470 | 4,625 | ||||||
Preferred stock | 75 | 73 | ||||||
Fair Value [Member] | Ameren Illinois Company [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||||
Long-term debt (including current portion) | 1,940 | 2,020 | ||||||
Preferred stock | 49 | 49 | ||||||
Carrying Amount [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||||
Long-term debt (including current portion) | 6,158 | [1],[2] | 6,157 | [1],[2] | ||||
Preferred stock | 142 | [1],[2] | 142 | [1],[2] | ||||
Carrying Amount [Member] | Ameren Missouri [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||||
Long-term debt (including current portion) | 4,006 | 4,006 | ||||||
Preferred stock | 80 | 80 | ||||||
Carrying Amount [Member] | Ameren Illinois Company [Member]
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Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||||||||
Long-term debt (including current portion) | 1,727 | 1,727 | ||||||
Preferred stock | $ 62 | $ 62 | ||||||
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Commitments And Contingencies (Asset Sale) (Details) (USD $)
In Millions, unless otherwise specified |
1 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
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Dec. 31, 2012
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Feb. 29, 2012
Medina Valley Energy Center [Member]
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Jun. 30, 2013
Medina Valley Energy Center [Member]
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Loss Contingencies [Line Items] | ||||
Proceeds from sale of property, plant, and equipment | $ 16 | |||
Nontrade Receivables | 1 | |||
Pretax gain from asset sale | 10 | |||
Receivable, charge-offs | 1 | |||
Current liabilities of discontinued operations | $ 1,183 | $ 1,166 |
Fair Value Measurements (Schedule Of Transfers Between Fair Value Hierarchy Levels) (Detail) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
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Jun. 30, 2012
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Mar. 31, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Derivative [Line Items] | |||||||||
Net fair value of Level 3 transfers | $ 3 | $ (1) | $ 2 | $ 185 | |||||
Fuel Oils [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | (2) | ||||||||
Fuel Oils [Member] | Transfer Into/Out of Level 1 [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | 2 | ||||||||
Natural Gas [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers out of Level 3 | 185 | ||||||||
Natural Gas [Member] | Transfer Into/Out of Level 2 [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers out of Level 3 | 185 | ||||||||
Power [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | 2 | ||||||||
Assets Transfers out of Level 3 | 3 | (1) | [1] | 4 | (2) | [1] | |||
Power [Member] | Transfer Into/Out of Level 2 [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | (2) | ||||||||
Assets Transfers out of Level 3 | 3 | (1) | 4 | (2) | |||||
Ameren Missouri [Member]
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Derivative [Line Items] | |||||||||
Net fair value of Level 3 transfers | 3 | (1) | 2 | 15 | |||||
Ameren Missouri [Member] | Fuel Oils [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | (2) | ||||||||
Ameren Missouri [Member] | Fuel Oils [Member] | Transfer Into/Out of Level 1 [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | 2 | ||||||||
Ameren Missouri [Member] | Natural Gas [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers out of Level 3 | 15 | ||||||||
Ameren Missouri [Member] | Natural Gas [Member] | Transfer Into/Out of Level 2 [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers out of Level 3 | 15 | ||||||||
Ameren Missouri [Member] | Power [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | 2 | ||||||||
Assets Transfers out of Level 3 | 3 | (1) | 4 | (2) | |||||
Ameren Missouri [Member] | Power [Member] | Transfer Into/Out of Level 2 [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers into Level 3 | (2) | ||||||||
Assets Transfers out of Level 3 | 3 | (1) | 4 | (2) | |||||
Ameren Illinois Company [Member] | Natural Gas [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers out of Level 3 | 170 | ||||||||
Ameren Illinois Company [Member] | Natural Gas [Member] | Transfer Into/Out of Level 2 [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers out of Level 3 | 170 | ||||||||
Ameren Illinois Company [Member] | Power [Member]
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Derivative [Line Items] | |||||||||
Assets Transfers out of Level 3 | |||||||||
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Rate And Regulatory Matters (Narrative-Missouri) (Detail) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | 3 Months Ended | 6 Months Ended | 1 Months Ended | 6 Months Ended | 3 Months Ended | |||||||
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Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
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Jun. 30, 2012
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Jun. 30, 2013
Ameren Missouri [Member]
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Jun. 30, 2012
Ameren Missouri [Member]
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Jun. 30, 2013
Ameren Missouri [Member]
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Jun. 30, 2012
Ameren Missouri [Member]
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Apr. 30, 2011
Ameren Missouri [Member]
Fac Prudence Review [Member]
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Jul. 31, 2011
Ameren Missouri [Member]
Accounting Authority Order Request [Member]
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Dec. 30, 2012
Electric Distribution [Member]
Ameren Missouri [Member]
Final Rate Order [Member]
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Jun. 30, 2013
Fac Prudence Review [Member]
Subsequent Periods After September 30, 2009 [Member]
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Jun. 30, 2013
Fac Prudence Review [Member]
Subsequent Periods After September 30, 2009 [Member]
MoPSC order [Member]
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Jun. 30, 2013
Fac Prudence Review [Member]
Subsequent Periods After September 30, 2009 [Member]
Ameren Missouri [Member]
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Rate And Regulatory Matters [Line Items] | ||||||||||||||
Contested amounts under the FAC | $ 18 | $ 3 | $ 26 | $ 23 | ||||||||||
Interest Charges | 100 | 98 | 201 | 196 | 56 | 56 | 116 | 112 | 1 | 1 | 1 | |||
Request to defer fixed costs not recovered from Noranda, amount | 36 | |||||||||||||
Authorized Increase in Revenue from Utility Service | $ 260 |
Commitments And Contingencies (Environmental Matters) (Detail) (USD $)
In Millions, unless otherwise specified |
6 Months Ended | |||||||||
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Jun. 30, 2013
State
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Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | $ 395 | [1] | ||||||||
Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 480 | [1] | ||||||||
Estimated Capital Costs 2012 [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 35 | [1] | ||||||||
Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 120 | [1] | ||||||||
Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 150 | [1] | ||||||||
Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 240 | [1] | ||||||||
Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 295 | [1] | ||||||||
Ameren Energy Generating Company [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 350 | [2] | ||||||||
Ameren Energy Generating Company [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 425 | [2] | ||||||||
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2012 [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 30 | [2] | ||||||||
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 100 | [2] | ||||||||
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 125 | [2] | ||||||||
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 220 | [2] | ||||||||
Ameren Energy Generating Company [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 270 | [2] | ||||||||
Ameren Missouri [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 1,115 | [3] | ||||||||
Ameren Missouri [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 1,340 | [3] | ||||||||
Ameren Missouri [Member] | Estimated Capital Costs 2012 [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 105 | [3] | ||||||||
Ameren Missouri [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 215 | [3] | ||||||||
Ameren Missouri [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 260 | [3] | ||||||||
Ameren Missouri [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 795 | [3] | ||||||||
Ameren Missouri [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 975 | [3] | ||||||||
AERG [Member] | Minimum [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 45 | |||||||||
AERG [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 55 | |||||||||
AERG [Member] | Estimated Capital Costs 2012 [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 5 | |||||||||
AERG [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Minimum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 20 | |||||||||
AERG [Member] | Estimated Capital Costs 2014 to 2017 [Member] | Maximum [Member]
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||||||||||
Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 25 | |||||||||
AERG [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Minimum [Member]
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||||||||||
Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 20 | |||||||||
AERG [Member] | Estimated Capital Costs 2018 to 2022 [Member] | Maximum [Member]
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state environmental regulations | 25 | |||||||||
CAIR [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Number of states participating in the cap-and-trade program | 28 | |||||||||
MATS [Member]
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Loss Contingencies [Line Items] | ||||||||||
Percent of top performing facilities | 12.00% | |||||||||
Former Coal Tar Distillery [Member] | Ameren Missouri [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Range of possible loss, minimum | 2.0 | |||||||||
Range of possible loss maximum | 5.0 | |||||||||
Accrual for environmental loss contingencies | 2.0 | |||||||||
Former Coal Ash Landfill [Member] | Ameren Illinois Company [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Range of possible loss, minimum | 0.5 | |||||||||
Range of possible loss maximum | 6.0 | |||||||||
Accrual for environmental loss contingencies | 0.5 | |||||||||
Newton Energy Center Scrubbers [Member] | Ameren Energy Generating Company [Member] | Newton Energy Center Estimated Capital Costs 2013 to 2017 [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Estimated capital costs to comply with existing and known federal and state air emissions regulations | 20 | |||||||||
Manufactured Gas Plant [Member]
|
||||||||||
Loss Contingencies [Line Items] | ||||||||||
Range of possible loss, minimum | 256.0 | |||||||||
Range of possible loss maximum | 339.0 | |||||||||
Accrual for environmental loss contingencies | 256.0 | [4] | ||||||||
Manufactured Gas Plant [Member] | Ameren Missouri [Member]
|
||||||||||
Loss Contingencies [Line Items] | ||||||||||
Range of possible loss, minimum | 5.0 | |||||||||
Range of possible loss maximum | 6.0 | |||||||||
Accrual for environmental loss contingencies | 5.0 | [4] | ||||||||
Manufactured Gas Plant [Member] | Ameren Illinois Company [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Number of remediation sites | 44 | |||||||||
Range of possible loss, minimum | 251.0 | |||||||||
Range of possible loss maximum | 333.0 | |||||||||
Accrual for environmental loss contingencies | 251.0 | [4] | ||||||||
Other Environmental [Member] | Ameren Illinois Company [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Accrual for environmental loss contingencies | 0.8 | |||||||||
Sauget Area Two [Member] | Ameren Missouri [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Range of possible loss, minimum | 0.3 | |||||||||
Range of possible loss maximum | 10.0 | |||||||||
Accrual for environmental loss contingencies | 0.3 | |||||||||
Substation in St Charles, Missouri [Member] | Ameren Missouri [Member]
|
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Loss Contingencies [Line Items] | ||||||||||
Range of possible loss, minimum | 1.7 | |||||||||
Range of possible loss maximum | 4.5 | |||||||||
Accrual for environmental loss contingencies | $ 1.7 | |||||||||
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Divestiture Transactions and Discontinued Operations (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures | The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at June 30, 2013, and December 31, 2012:
The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three and six months ended June 30, 2013, and 2012:
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Schedule Of Coverage Ratios | Indenture Provisions and Other Covenants Ameren Missouri’s and Ameren Illinois’ indentures and articles of incorporation include covenants and provisions related to issuances of first mortgage bonds and preferred stock. Ameren Missouri and Ameren Illinois are required to meet certain ratios to issue additional first mortgage bonds and preferred stock. A failure to achieve these ratios would not result in a default under these covenants and provisions, but would restrict the companies’ ability to issue bonds or preferred stock. The following table summarizes the required and actual interest coverage ratios for interest charges and dividend coverage ratios and bonds and preferred stock issuable as of June 30, 2013, at an assumed annual interest rate of 6% and dividend rate of 7%.
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Ameren Energy Generating Company [Member]
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Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule Of Coverage Ratios | Genco Indenture Provisions Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the 12 months ended and as of June 30, 2013:
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Consolidated Balance Sheet (Parenthetical) (USD $)
In Millions, except Per Share data, unless otherwise specified |
Jun. 30, 2013
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Dec. 31, 2012
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Accounts receivable - trade allowance for doubtful accounts | $ 22 | $ 17 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 400.0 | 400.0 |
Common stock, shares outstanding | 242.6 | 242.6 |
Union Electric Company [Member]
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Accounts receivable - trade allowance for doubtful accounts | 6 | 5 |
Common stock, par value | $ 5 | $ 5 |
Common stock, shares authorized | 150.0 | 150.0 |
Common stock, shares outstanding | 102.1 | 102.1 |
Ameren Illinois Company [Member]
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Accounts receivable - trade allowance for doubtful accounts | $ 16 | $ 12 |
Common stock, no par value | ||
Common stock, shares authorized | 45.0 | 45.0 |
Common stock, shares outstanding | 25.5 | 25.5 |
Summary Of Significant Accounting Policies
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Jun. 30, 2013
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Accounting Policies [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are its equity interests in its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets, and liabilities. These subsidiaries operate, as the case may be, rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and merchant electric generation businesses. Dividends on Ameren’s common stock and the payment of expenses by Ameren depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report and in the Form 10-K.
Ameren has various other subsidiaries responsible for activities such as the provision of shared services. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Immediately prior to Ameren’s entry into the transaction agreement with IPH, on March 14, 2013, Genco exercised its option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the pending sale of its Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley, which is subject to FERC approval. Ameren has commenced a sale process for these three gas-fired energy centers and expects a third-party sale to be completed during 2013. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding these divestitures. As a result of the transaction agreement with IPH and Ameren’s plan to sell its Elgin, Gibson City, and Grand Tower gas-fired energy centers, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation. Therefore, Ameren has segregated New AER’s and the Elgin, Gibson City, and Grand Tower gas-fired energy centers’ operating results, assets, and liabilities and presented them separately as discontinued operations for all periods presented in this report. Unless otherwise noted, these notes to Ameren’s financial statements have been revised to exclude discontinued operations for all periods presented. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information regarding that presentation. The financial statements of Ameren are prepared on a consolidated basis. Ameren Missouri and Ameren Illinois have no subsidiaries, and therefore their financial statements are not prepared on a consolidated basis. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated. Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) that are necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. The results of operations of an interim period may not give a true indication of results that may be expected for a full year. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. During preparation of the 2012 annual statements of cash flows, it was identified that Ameren’s and Ameren Missouri’s 2012 interim statements of cash flows incorrectly classified certain activity from the nuclear decommissioning trust fund. Although not material, operating cash flows were overstated by $14 million, $26 million, and $49 million for the year-to-date periods ended March, 31, 2012, June 30, 2012, and September 30, 2012, respectively. The overstated operating cash flows resulted in the investing cash flows being understated by the same amounts. The cash flows for the six months ended June 30, 2012, for Ameren and Ameren Missouri have been revised in this report to correct for this error. The cash flows for the nine months ended September 30, 2012, will be revised to correct for this error in the Ameren and Ameren Missouri reports for the quarter ending September 30, 2013. Earnings Per Share There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three and six months ended June 30, 2013, and 2012. The number of dilutive restricted stock shares and performance share units had an immaterial impact on earnings per share. Stock-based Compensation A summary of nonvested performance share units at June 30, 2013, and changes during the six months ended June 30, 2013, under the 2006 Omnibus Incentive Compensation Plan (2006 Plan) are presented below:
The fair value of each share unit awarded in 2013 under the 2006 Plan was determined to be $31.19. That amount was based on Ameren’s closing common share price of $30.72 at December 31, 2012, and lattice simulations. Lattice simulations are used to estimate expected share payout based on Ameren’s total stockholder return for a three-year performance period relative to the designated peer group beginning January 1, 2013. The simulations can produce a greater fair value for the share unit than the applicable closing common share price because they include the weighted payout scenarios in which an increase in the share price has occurred. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 0.36%, volatility of 12% to 21% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period. Intangible Assets Ameren and Ameren Missouri classify emission allowances and renewable energy credits as intangible assets. Ameren Illinois consumes renewable energy credits as they are purchased through the IPA procurement process and expenses them immediately. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. At June 30, 2013, Ameren’s and Ameren Missouri’s intangible assets consisted of renewable energy credits obtained through wind and solar power purchase agreements. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $18 million and $18 million, respectively, at June 30, 2013. The book value of Ameren’s and Ameren Missouri’s renewable energy credits was $14 million and $14 million, respectively, at December 31, 2012. Renewable energy credits and emission allowances are charged to purchased power expense and fuel expense, respectively, as they are used in operations. In accordance with the MoPSC's 2012 electric rate order, the majority of Ameren Missouri's amortization of intangible assets is deferred as a regulatory asset pending future recovery from customers through rates. The following table presents amortization expense based on usage of renewable energy credits and emission allowances, net of gains from sales, for Ameren, Ameren Missouri, and Ameren Illinois, during the three and six months ended June 30, 2013, and 2012.
Excise Taxes Excise taxes levied on us are reflected on Ameren Missouri electric customer bills and on Ameren Missouri and Ameren Illinois natural gas customer bills. They are recorded gross in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” on the statement of income or the statement of income and comprehensive income. Excise taxes reflected on Ameren Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in “Taxes accrued” on the balance sheet. The following table presents excise taxes recorded in “Operating Revenues - Electric,” “Operating Revenues - Gas” and “Operating Expenses - Taxes other than income taxes” for the three and six months ended June 30, 2013, and 2012:
Uncertain Tax Positions The amount of unrecognized tax benefits as of June 30, 2013, was $193 million, $127 million, and $4 million, for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits (detriments) as of June 30, 2013, that would impact the effective tax rate, if recognized, was $49 million, less than $1 million, and $(1) million for Ameren, Ameren Missouri, and Ameren Illinois, respectively. The amount of unrecognized tax benefits that would impact the effective tax rate, if recognized, for Ameren increased by $48 million as of June 30, 2013, all of which occurred during the first quarter of 2013. This increase is primarily due to uncertainty related to the historical computation of Ameren’s tax basis in its stock investment in AER. Ameren’s federal income tax returns for the years 2007 through 2011 are before the Appeals Office of the Internal Revenue Service. Ameren’s federal income tax return for the year 2012 is currently under examination. It is reasonably possible that a settlement will be reached with the Appeals Office of the Internal Revenue Service in the next 12 months for the years 2007 through 2010. This settlement, which is primarily related to uncertain tax positions for capitalization versus currently deductible repair expense and research tax deductions, is expected to result in a decrease in uncertain tax benefits of $126 million, $110 million, and $5 million for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, it is reasonably possible that other events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe any such increases or decreases, including the decrease from the reasonably possible IRS Appeals Office settlement discussed above, would be material to their results of operations, financial position, or liquidity. State income tax returns are generally subject to examination for a period of three years after filing of the return. The Ameren Companies do not currently have material state income tax issues under examination, administrative appeals, or litigation. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Ameren Missouri has an uncertain tax position tracker. Under Missouri’s regulatory framework, uncertain income tax positions do not reduce Ameren Missouri’s electric rate base. When an uncertain income tax position liability is resolved, the MoPSC requires, through the uncertain tax position tracker, the creation of a regulatory asset or regulatory liability to reflect the time value (using the weighted-average cost of capital included in each of the electric rate orders in effect before the tax position was resolved) of the difference between the uncertain income tax position liability that was excluded from rate base and the final tax liability. The resulting regulatory asset or liability will be amortized over three years beginning on the effective date of new rates established in the next electric rate case. Asset Retirement Obligations AROs at Ameren, Ameren Missouri, and Ameren Illinois increased compared to December 31, 2012, to reflect the accretion of obligations to their fair values. Based on the transaction agreement to divest New AER to IPH, Ameren will retain the AROs associated with the Meredosia and Hutsonville energy centers. Therefore, these AROs are classified as continuing operations. See Note 2 - Divestiture Transactions and Discontinued Operations for additional information. Noncontrolling Interest Ameren's noncontrolling interests comprised the 20% of EEI not owned by Ameren and the preferred stock not subject to mandatory redemption of Ameren's subsidiaries. These noncontrolling interests were classified as a component of equity separate from Ameren's equity on its consolidated balance sheet. A reconciliation of the equity changes attributable to the noncontrolling interests at Ameren for the three and six months ended June 30, 2013, and 2012, is shown below:
Accounting and Reporting Developments The following is a summary of recently adopted authoritative accounting guidance that could impact the Ameren Companies. Presentation of Comprehensive Income In June 2011, FASB amended its guidance on the presentation of comprehensive income in financial statements. The amended guidance changed the presentation of comprehensive income in the financial statements. It requires entities to report components of comprehensive income either in a continuous statement of comprehensive income or in two separate but consecutive statements. This guidance was effective for the Ameren Companies beginning in the first quarter of 2012 with retroactive application required. The implementation of the amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity. In February 2013, FASB amended this guidance to require an entity to provide information about the amounts reclassified out of accumulated OCI by component. In addition, an entity is required to present significant amounts reclassified out of accumulated OCI by the respective line items of net income either on the face of the statement where net income is presented or in the footnotes. This guidance was effective for the Ameren Companies beginning in the first quarter of 2013. The implementation of this amended guidance did not affect the Ameren Companies’ results of operations, financial position, or liquidity. The only amounts reclassified out of accumulated OCI for the Ameren Companies related to pension and other postretirement plan activity. These amounts were immaterial during the first and second quarters of 2013, and therefore no additional disclosures were required. Disclosures about Offsetting Assets and Liabilities In December 2011, FASB issued additional authoritative accounting guidance to improve information disclosed about financial and derivative instruments. The guidance requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. In January 2013, FASB amended this guidance to limit the scope to derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions. The Ameren Companies adopted this guidance for the first quarter of 2013. The implementation of this additional guidance did not affect the Ameren Companies’ results of operations, financial positions, or liquidity, as this guidance only requires additional disclosures. See Note 7 - Derivative Financial Instruments for the required additional disclosures. Presentation of an Unrecognized Tax Benefit In July 2013, FASB issued additional authoritative accounting guidance to provide explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The objective of this guidance is to eliminate diversity in practice related to the presentation of certain unrecognized tax benefits. It requires entities to present an unrecognized tax benefit as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward to the extent a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is available under the tax law. The amended guidance will not affect the Ameren Companies' results of operations, financial position, or liquidity, as this guidance is presentation-related only. This guidance will be effective for the Ameren Companies beginning in the first quarter of 2014. |
Short-Term Debt And Liquidity
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6 Months Ended |
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Jun. 30, 2013
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Line of Credit Facility [Abstract] | |
SHORT-TERM DEBT AND LIQUIDITY | SHORT-TERM DEBT AND LIQUIDITY The liquidity needs of the Ameren Companies are typically supported through the use of available cash, short-term intercompany borrowings, drawings under committed bank credit agreements, or commercial paper issuances. The 2012 Missouri Credit Agreement and the 2012 Illinois Credit Agreement were not utilized for borrowings during the six months ended June 30, 2013. As of June 30, 2013, based on letters of credit issued under the 2012 Credit Agreements, as well as commercial paper outstanding, the aggregate amount of credit capacity available to Ameren (parent), Ameren Missouri and Ameren Illinois, collectively, at June 30, 2013, was $2.06 billion. Commercial Paper At June 30, 2013, Ameren had $25 million of commercial paper outstanding. The average daily commercial paper balances outstanding during the six months ended June 30, 2013, and 2012, were $13 million and $72 million, respectively. The weighted-average interest rates during the six months ended June 30, 2013, and 2012, were 0.54% and 0.94%, respectively. The peak short-term commercial paper balances outstanding during the six months ended June 30, 2013, and 2012, were $78 million and $229 million, respectively. The peak interest rates during the six months ended June 30, 2013, and 2012, were 0.85% and 1.25%, respectively. Ameren Missouri and Ameren Illinois did not utilize their commercial paper programs during the six months ended June 30, 2013, and 2012. Indebtedness Provisions and Other Covenants The information below presents a summary of the Ameren Companies’ compliance with indebtedness provisions and other covenants within the 2012 Credit Agreements. See Note 4 – Short-term Debt and Liquidity under Part II, Item 8, in the Form 10-K for a detailed description of these provisions. The 2012 Credit Agreements contain nonfinancial covenants, including restrictions on the ability to incur liens, to transact with affiliates, to dispose of assets, to make investments in or transfer assets to its affiliates, and to merge with other entities. The 2012 Credit Agreements require each of Ameren, Ameren Missouri and Ameren Illinois to maintain consolidated indebtedness of not more than 65% of its consolidated total capitalization pursuant to a defined calculation set forth in the agreements. As of June 30, 2013, the ratios of consolidated indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the 2012 Credit Agreements, were 52%, 48% and 42%, for Ameren, Ameren Missouri and Ameren Illinois, respectively. In addition, under the 2012 Illinois Credit Agreement and by virtue of the cross-default provisions of the 2012 Missouri Credit Agreement, Ameren is required to maintain a ratio of consolidated funds from operations plus interest expense to consolidated interest expense of 2.0 to 1, to be calculated quarterly, as of the end of the most recent four fiscal quarters then ending, in accordance with the 2012 Illinois Credit Agreement. Ameren’s ratio as of June 30, 2013, was 4.9 to 1.0. Failure of a borrower to satisfy a financial covenant constitutes an immediate default under the applicable 2012 Credit Agreement. Ameren’s ratios, as discussed above, include both continuing and discontinued operations for the purposes of these calculations. None of the Ameren Companies' credit agreements or financing arrangements contain credit rating triggers that would cause a default or acceleration of repayment of outstanding balances. Management believes that the Ameren Companies were in compliance with the provisions and covenants of their credit agreements at June 30, 2013. Money Pools Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for the operation and administration of the money pool agreements. Utility Ameren Missouri, Ameren Illinois and Ameren Services may participate in the utility money pool as both lenders and borrowers. Ameren (parent) and AERG may participate in the utility money pool only as lenders. Internal funds are surplus funds contributed to the utility money pool from participants. The primary sources of external funds for the utility money pool are the 2012 Credit Agreements and the commercial paper programs. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the utility money pool or remit funds from other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. The utility money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the utility money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rates for borrowing under the utility money pool for the three and six months ended June 30, 2013, were 0.07% and 0.09%, respectively (2012 - 0.14% and 0.12%, respectively). Non-state-regulated Subsidiaries Ameren (parent), Ameren Services, AER, Genco, AERG, Marketing Company, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company and applicable regulatory short-term borrowing authorizations, to access funding from the 2012 Credit Agreements and the commercial paper programs through a non-state-regulated subsidiary money pool agreement. AER, Genco, AERG and Marketing Company may participate in the non-state-regulated money pool through the closing of the divestiture transaction as detailed in Note 2 - Divestiture Transactions and Discontinued Operations. All participants may borrow from or lend to the non-state-regulated money pool, except for Ameren Services, which may participate only as a borrower. The total amount available to the pool participants from the non-state-regulated subsidiary money pool at any given time is reduced by the amount of borrowings made by participants, but is increased to the extent that the pool participants advance surplus funds to the non-state-regulated subsidiary money pool or remit funds from other external sources. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for the participants. Participants receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. The average interest rates for borrowing under the non-state-regulated subsidiary money pool for the three and six months ended June 30, 2013, were 0.29% and 0.26%, respectively (2012 - 0.64% and 0.70%, respectively). See Note 9 - Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the three and six months ended June 30, 2013, and 2012. |
Callaway Energy Center (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified |
12 Months Ended | 6 Months Ended | 12 Months Ended | |
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Dec. 31, 2011
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Dec. 31, 2010
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Jun. 30, 2013
Nuclear Plant [Member]
mill
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Dec. 31, 2012
Nuclear Plant [Member]
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Nuclear Waste Matters [Line Items] | ||||
Number of mills charged for NWF fee | 1 | |||
Settlement payment | $ 6 | |||
Assumed life of plant, in years | 40 years | |||
Annual decommissioning costs included in costs of service | $ 7 | $ 7 | $ 7 | |
Missouri Public Service Commission, Requirement to file updated cost study and funding analysis for decommissioning energy center, Period | 3 years |
Divestiture Transactions and Discontinued Operations (Notes)
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Jun. 30, 2013
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Discontinued Operations and Disposal Groups [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS | DIVESTITURE TRANSACTIONS AND DISCONTINUED OPERATIONS Transaction Agreement with IPH On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. Under the terms of the transaction agreement, AER will effect a reorganization that will, among other things, transfer substantially all of the assets and liabilities of AER, other than (i) any outstanding debt obligations of AER to Ameren or its other subsidiaries, except for certain intercompany balances discussed below, (ii) all of the issued and outstanding equity interests in Medina Valley, which were distributed to Ameren in March 2013, (iii) the assets and liabilities associated with Genco’s Meredosia, Hutsonville, Elgin, Gibson City, and Grand Tower energy centers, (iv) the obligations relating to Ameren's single-employer pension and postretirement benefit plans, and (v) the deferred tax positions associated with Ameren's ownership of these retained assets and liabilities, to New AER. IPH will acquire all of the equity interests in New AER. Ameren will retain the pension and postretirement benefit obligations associated with current and former employees of AER that are included in the Ameren Retirement Plan, the Ameren Supplemental Retirement Plan, the Ameren Retiree Medical Plan, and the Ameren Group Life Insurance Plan. This noncurrent obligation is reflected on Ameren’s consolidated balance sheet as “Pension and other postretirement benefits.” IPH will assume the pension and other postretirement benefit obligations associated with EEI’s current and former employees that are included in the Revised Retirement Plan for Employees of Electric Energy, Inc., the Group Insurance Plan for Management Employees of Electric Energy, Inc., and the Group Insurance Plan for Bargaining Unit Employees of Electric Energy, Inc. The obligations to be assumed by IPH are estimated at $37 million at June 30, 2013. IPH will also acquire the estimated $15 million asset at June 30, 2013, relating to the overfunded status of one of EEI’s postretirement plans. Ameren will retain Genco’s Meredosia and Hutsonville energy centers, which are no longer in operation and had an immaterial property and plant asset balance as of June 30, 2013. Ameren will also retain AROs associated with these energy centers, estimated at $27 million as of June 30, 2013. All other AROs associated with AER are expected to be assumed by either IPH or the third-party buyer of the Grand Tower energy center. Upon the transaction agreement closing, with the exception of certain agreements, such as supply obligations to Ameren Illinois, a note from New AER to Ameren relating to cash collateral that will remain outstanding at closing, and Genco money pool advances, all intercompany agreements and debt between AER and its subsidiaries, on the one hand, and Ameren and its non-AER affiliates, on the other hand, will be either retained or cancelled by Ameren, without any cost or obligation to IPH or New AER and its subsidiaries. Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren, which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Cash collateral postings by AER and its subsidiaries with external parties, including postings related to exchange-traded contracts, at June 30, 2013, were $29 million. Genco's $825 million in aggregate principal amount of senior notes will remain outstanding following the closing of the transaction agreement and will continue to be solely obligations of Genco. Pursuant to the transaction agreement, in addition to the cash paid to Genco for the Elgin, Gibson City, and Grand Tower energy center sale, Ameren will cause $85 million of cash to be retained at New AER. As a condition to the transaction agreement, Genco exercised the amended put option agreement for the sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013. Completion of the New AER sale to IPH is subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On April 16, 2013, AER and Dynegy filed with FERC an application for approval of the divestiture of New AER and Genco’s sale of the Elgin, Gibson City, and Grand Tower natural gas-fired energy centers to Medina Valley. On July 26, 2013, FERC issued an order seeking additional information. In early August 2013, AER and Dynegy responded to FERC’s request for additional information. Several wholesale customers filed a protest with FERC regarding the application. Separately, as a condition to IPH’s obligation to complete the New AER transaction, the Illinois Pollution Control Board must approve the transfer to IPH of, or otherwise approve a variance in favor of IPH on the same terms as, AER’s variance of the Illinois MPS. In May 2013, AER and IPH filed a transfer request with the Illinois Pollution Control Board, which was subsequently denied by the board on procedural grounds. On July 22, 2013, IPH, AER, and Medina Valley, as current and future owners of the coal-fired energy centers, filed a request for a variance with the Illinois Pollution Control Board seeking the same relief as the existing AER variance. The Illinois Pollution Control Board has until late November 2013 to issue a decision. See Note 10 - Commitments and Contingencies for additional information. Ameren’s and IPH’s obligation to complete the transaction is also subject to other customary closing conditions, including the material accuracy of each company’s representations and warranties and the compliance, in all material respects, with each company’s covenants. The transaction agreement contains customary representations and warranties of Ameren and IPH, including representations and warranties of Ameren with respect to the business being sold. The transaction agreement also contains customary covenants of Ameren and IPH, including the covenant of Ameren that AER will be operated in the ordinary course prior to the closing. Ameren expects the closing of the New AER divestiture to IPH will occur in the fourth quarter of 2013. If the closing does not occur on or before March 14, 2014, subject to a one-month extension to obtain FERC approval, either party may elect to terminate the transaction agreement if the inability to close the transaction by such date is not the result of the failure of the terminating company to fulfill any of its obligations under the transaction agreement. Amended Put Option Agreement, Asset Purchase Agreement and Guaranty See Note 9 - Related Party Transactions for additional information regarding the original put option agreement between Genco and AERG that was entered into on March 28, 2012. Prior to entry into the transaction agreement with IPH as discussed above, (i) the original put option agreement between Genco and AERG was novated and amended such that the rights and obligations of AERG under the agreement were assigned to and assumed by Medina Valley and (ii) Genco exercised its option under the amended put option agreement to sell the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. As a result, on March 14, 2013, Genco received an initial payment of $100 million in accordance with the terms of the amended put option agreement. Genco advanced the initial payment amount it received into the non-state-regulated subsidiary money pool. In connection with the amended put option agreement, Ameren's guaranty, dated March 28, 2012, was modified to replace all references to AERG with references to Medina Valley. Pursuant to the amended put option agreement, Genco and Medina Valley entered into an asset purchase agreement, dated March 14, 2013. Genco and Medina Valley have engaged three appraisers to conduct a fair market valuation of the Elgin, Gibson City, and Grand Tower gas-fired energy centers, which valuations will be averaged and subject to adjustment at the closing of the asset purchase agreement to reflect the assets and liabilities associated with the Elgin, Gibson City, and Grand Tower gas-fired energy centers. At the closing, Genco will receive an additional amount equal to the greater of (i) $33 million, or (ii) the appraised value of the Elgin, Gibson City, and Grand Tower gas-fired energy centers less the initial payment of $100 million, for a total purchase price of at least $133 million, and Genco will sell and transfer to Medina Valley all of its rights in the Elgin, Gibson City, and Grand Tower gas-fired energy centers as a condition to the transaction agreement. If these gas-fired energy centers are subsequently sold by Medina Valley within two years of the asset purchase agreement closing, Medina Valley will pay Genco any proceeds from such sale, net of taxes and other expenses, in excess of the amounts previously paid to Genco. Ameren has commenced a sale process for these three energy centers and expects a third-party sale will be completed during 2013. Should FERC approval not be obtained and the transfer of the Elgin, Gibson City, and Grand Tower energy centers to Medina Valley cannot be completed, Genco will be required to return to Medina Valley the initial payment received in March 2013. The asset purchase agreement contains customary representations, warranties and covenants of Genco and Medina Valley. The consummation of the transactions contemplated by the asset purchase agreement is subject to certain conditions, including the receipt of FERC approval and other customary conditions. Discontinued Operations Presentation As of March 14, 2013, Ameren determined that New AER and the Elgin, Gibson City, and Grand Tower gas-fired energy centers qualified for discontinued operations presentation and, therefore, were classified separately in Ameren’s consolidated financial statements as discontinued operations for all periods presented in this report. Ameren concluded that New AER and collectively the Elgin, Gibson City, and Grand Tower gas-fired energy centers are two separate disposal groups. Both disposal groups have been aggregated in the disclosures below. Each disposal group was measured at fair value on a nonrecurring basis with inputs that are classified as Level 3 within the fair value hierarchy. The following table presents the components of discontinued operations in Ameren's consolidated statement of income (loss) for the three and six months ended June 30, 2013, and 2012:
As the New AER disposal group continued to meet the discontinued operations criteria at June 30, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the terms of Ameren’s agreement to divest New AER to IPH. Ameren will receive no cash proceeds from IPH for the divestiture of New AER. Ameren recorded a pretax charge to earnings of $155 million for the three months ended March 31, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. The pretax charge to earnings increased by $13 million during the three months ended June 30, 2013, as the disposal group’s carrying value increased, primarily as a result of derivative market value gains. Ameren recorded a cumulative pretax charge to earnings of $168 million for the six months ended June 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. The impairment loss was recorded in “Operating expenses” within the components of the discontinued operations statement of income (loss) with a corresponding reduction in “Property and Plant, net” within the components of the discontinued operations balance sheet. Ameren estimated the impairment loss of the disposal group based on the estimated fair value pursuant to the terms of the transaction agreement with IPH, using information currently available, and assuming an expected fourth quarter 2013 closing. Actual operating results, derivative market values, capital expenditures and other items will impact the ultimate loss recognized to reduce the carrying value of the New AER disposal group to its actual fair value less cost to sell, which will be recorded in discontinued operations after all of the information becomes available. In addition, any curtailment gain related to Ameren's pension and postretirement plans will be recorded when the related employees terminate employment with Ameren. The ultimate impairment loss may differ materially from the estimated loss recorded as of June 30, 2013. Ameren adjusted accumulated deferred income taxes on its balance sheet to reflect the excess of tax basis over financial reporting basis of its stock investment in AER, during the three months ended March 31, 2013, when it became apparent that the temporary difference would reverse. This change in basis resulted in a discontinued operations deferred tax expense of $98 million, which was partially offset by the expected tax benefits of $63 million related to the pretax loss from discontinued operations including the impairment charge, during the three months ended March 31, 2013. During the second quarter of 2013, Ameren recorded tax benefits of $6 million related to the incremental pretax loss from discontinued operations recorded during the second quarter of 2013. In addition, Ameren recorded a $1 million reduction in discontinued operations deferred tax expense during the second quarter of 2013 to reflect the excess of tax basis over financial reporting basis of Ameren’s stock investment in AER. Ameren recorded a cumulative discontinued operations deferred tax expense of $97 million, which was partially offset by the expected tax benefits of $69 million related to the pretax loss from discontinued operations including the impairment charge, during the six months ended June 30, 2013. The final tax basis of the AER disposal group and the related tax benefit resulting from the transaction agreement with IPH are dependent upon taxable losses utilized by the disposal group through the closing and the resolution of tax matters under audit, including the adoption of recently issued guidance from the IRS related to tangible property repairs and other matters. As a result, tax expense and benefits realized in discontinued operations may differ materially from those recorded as of June 30, 2013. As the Elgin, Gibson City, and Grand Tower energy center disposal group continued to meet the discontinued operations criteria at June 30, 2013, Ameren evaluated whether any impairment existed by comparing the disposal group’s carrying value to the estimated fair value of the disposal group, less cost to sell. The fair value was based on the appraised value of these three gas-fired energy centers. In December 2012, Ameren recorded a noncash long-lived asset impairment charge to reduce the carrying value of AER’s energy centers, including the Elgin, Gibson City, and Grand Tower energy centers, to their estimated fair values under the accounting guidance for held and used assets. An immaterial impairment was recorded by Ameren for the three gas-fired energy centers during the three months ended March 31, 2013, with no adjustment necessary during the three months ended June 30, 2013, as the December 2012 held and used asset impairment charge reduced these energy centers’ disposal group carrying value to their estimated fair value of $133 million. Ameren does not expect to have significant continuing involvement or material cash flows with the Elgin, Gibson City, and Grand Tower energy centers after their sale. Effective with its conclusion that the New AER disposal group and the Elgin, Gibson City, and Grand Tower energy centers’ disposal group each met the criteria for held for sale presentation, Ameren suspended recording depreciation on these assets in March 2013. Interest on Genco’s senior notes, which will continue to be solely obligations of Genco following the closing of the transaction agreement with IPH, are included in the “Interest charges” component within the discontinued operations line item in the statement of income (loss). Ameren did not allocate corporate interest to the disposal groups. Additionally, general corporate overhead expenses originally allocated to the disposal groups were classified as expenses of continuing operations. The following table presents the carrying amounts of the components of assets and liabilities segregated on Ameren's consolidated balance sheets as discontinued operations at June 30, 2013, and December 31, 2012:
Ameren will have continuing transactions with New AER after the divestiture is complete. Ameren Illinois has power supply agreements with Marketing Company, which are a result of the power procurement process in Illinois administered by the IPA as required by the Illinois Public Utilities Act. Ameren Illinois will continue to purchase power and purchase trade receivables as required by Illinois law, and Ameren will reflect these items as continuing operations after the divestiture occurs. Ameren Illinois and ATXI currently sell, and will continue to sell, transmission services to Marketing Company after the divestiture of New AER is completed. Also, upon the divestiture of New AER, the transaction agreement requires Ameren (parent) to maintain its financial obligations with respect to all credit support provided to New AER for all transactions entered into prior to the closing of such divestiture for up to 24 months after the closing. IPH shall indemnify Ameren for any payments Ameren makes pursuant to these credit support obligations if the counterparty does not return the posted collateral to Ameren. IPH’s indemnification obligation will be secured by certain AERG and Genco assets. In addition, Dynegy has provided a limited guarantee of $25 million to Ameren (parent) pursuant to which Dynegy will, among other things, guarantee IPH’s indemnification obligations for a period of up to 24 months after the closing (subject to certain exceptions). Immediately prior to the transaction agreement closing, the cash collateral provided to New AER by Ameren through money pool borrowings will be converted to a note payable to Ameren which will be payable, with interest, 24 months after closing or sooner as cash collateral requirements are reduced. Also, within 120 days after closing, a working capital adjustment will be finalized, which may result in a cash payment from Ameren to New AER. Ameren has determined that the continuing cash flows generated by these arrangements are not significant and, accordingly, are not deemed direct cash flows of the divested business. Additionally, these arrangements do not provide Ameren the ability to significantly influence the operating results of New AER after the divestiture is complete. See Note 9 - Related Party Transactions for additional information regarding existing transactions between Ameren and New AER. For a period of up to 12 months following the closing, Ameren will provide certain transitional services to IPH. Such services will be provided at no charge for 90 days, subject to a $5 million limit; thereafter, services will be provided at cost, except for certain services that may be applied to the $5 million limit to the extent such limit has not been reached by the end of the 90 day period. The transitional services may be provided for six months after the closing and can be extended by IPH on a month-to-month basis for up to an additional six months. See Note 10 - Commitments and Contingencies for information regarding amendments to the plant transfer agreements between both Genco and Ameren Illinois and AERG and Ameren Illinois as well as other AER related contingencies. Genco Indenture Provisions Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these ratios for the 12 months ended and as of June 30, 2013:
Genco’s debt incurrence-related ratio restrictions under its indenture may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. As shown in the table above, under the provisions of Genco’s indenture, Genco may not borrow additional funds from external, third-party sources if its interest coverage ratio is less than 2.5 or its debt-to-capital ratio is greater than 60%. Beginning in the first quarter of 2013, Genco’s interest coverage ratio fell to a value less than the specified minimum level required for external borrowings, and Genco expects the ratio to remain less than this minimum level through at least 2015. As a result, Genco’s ability to borrow additional funds from external third-party sources is restricted. Genco’s indenture does not restrict intercompany borrowings from Ameren’s non-state-regulated subsidiary money pool. However, borrowings from the money pool are subject to Ameren’s control. If a Genco intercompany financing need were to arise, borrowings from the non-state-regulated subsidiary money pool by Genco would be dependent on consideration by Ameren of the facts and circumstances existing at that time. As stated above, the transaction agreement requires Ameren to operate New AER, including Genco, in the ordinary course prior to the closing. |
Divestiture Transactions and Discontinued Operations (Components of Assets and Liabilities) (Details) (USD $)
In Millions, unless otherwise specified |
Jun. 30, 2013
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Dec. 31, 2012
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Current assets of discontinued operations | ||||||||
Cash and cash equivalents | $ 25 | $ 25 | ||||||
Accounts receivable and unbilled revenue | 102 | 102 | ||||||
Materials and supplies | 119 | 134 | ||||||
Mark-to-market derivative assets | 111 | 102 | ||||||
Property and plant, net | 615 | 748 | ||||||
Accumulated deferred income taxes, net | 380 | 373 | ||||||
Other assets | 134 | 116 | ||||||
Total current assets of discontinued operations | 1,486 | 1,600 | ||||||
Current liabilities of discontinued operations | ||||||||
Accounts payable and other current obligations | 142 | 133 | ||||||
Mark-to-market derivative liabilities | 70 | 63 | ||||||
Long-term debt, net | 824 | 824 | ||||||
Asset retirement obligations | 87 | 78 | ||||||
Pension and other postretirement benefits | 37 | 40 | ||||||
Other liabilities | 23 | 28 | ||||||
Total current liabilities of discontinued operations | 1,183 | 1,166 | ||||||
Accumulated other comprehensive gain (loss) | 8 | [1] | 19 | [1] | ||||
Noncontrolling Interest | $ 8 | [2] | $ 8 | [2] | ||||
Electric Energy, Inc [Member]
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Current liabilities of discontinued operations | ||||||||
Percentage of EEI not owned by Ameren | 20.00% | 20.00% | ||||||
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Derivative Financial Instruments (Tables)
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Jun. 30, 2013
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Open Gross Derivative Volumes By Commodity Type | The following table presents open gross commodity contract volumes by commodity type as of June 30, 2013, and December 31, 2012:
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Derivative Instruments Carrying Value | The following table presents the carrying value and balance sheet location of all derivative instruments as of June 30, 2013, and December 31, 2012:
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Cumulative Pretax Net Gains (Losses) On All Derivative Instruments In OCI | The following table presents the cumulative amount of pretax net gains (losses) on all derivative instruments deferred in regulatory assets or regulatory liabilities as of June 30, 2013, and December 31, 2012:
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Offsetting Derivative Assets and Liabilities | The following table provides the recognized gross derivative balances and the net amounts of those derivatives subject to an enforceable master netting arrangement or similar agreement as of June 30, 2013, and December 31, 2012:
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Maximum Exposure If Counterparties Fail To Perform On Contracts | The maximum exposure is based on the gross fair value of financial instruments, including accrual and NPNS contracts, which excludes collateral held, and does not consider the legally binding right to net transactions based on master trading and netting agreements.
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Potential Loss On Counterparty Exposures | The following table presents the potential loss after consideration of collateral and application of master trading and netting agreements as of June 30, 2013, and December 31, 2012:
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Derivative Instruments With Credit Risk-Related Contingent Features | The additional collateral required is the net liability position allowed under the master trading and netting agreements, assuming (1) the credit risk-related contingent features underlying these agreements were triggered on June 30, 2013, or December 31, 2012, respectively, and (2) those counterparties with rights to do so requested collateral:
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Derivatives That Qualify For Regulatory Deferral | The following table represents the net change in market value for derivatives that qualify for regulatory deferral for the three and six months ended June 30, 2013, and 2012:
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Retirement Benefits (Tables)
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6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Jun. 30, 2013
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Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components Of Net Periodic Benefit Cost | The following table presents the components of the net periodic benefit cost for Ameren’s pension and postretirement benefit plans for the three and six months ended June 30, 2013, and 2012:
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Summary Of Benefit Plan Costs Incurred | Ameren Missouri and Ameren Illinois are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the three and six months ended June 30, 2013, and 2012:
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Commitments And Contingencies (Asbestos-Related Litigation And Tax Exemptions And Credits) (Detail) (USD $)
In Millions, unless otherwise specified |
6 Months Ended | 1 Months Ended | 3 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2013
Asbestos-Related [Member]
defendant
lawsuit
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Jun. 30, 2013
Asbestos-Related [Member]
Ameren Missouri [Member]
lawsuit
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Jun. 30, 2013
Asbestos-Related [Member]
Ameren Illinois Company [Member]
lawsuit
|
Jun. 30, 2013
Asbestos-Related [Member]
Ameren Corporation [Member]
lawsuit
|
Jun. 30, 2013
Collectibility of Taxes [Member]
Ameren Illinois Company [Member]
customer
|
Jul. 31, 2013
Collectibility of Taxes [Member]
Ameren Illinois Company [Member]
Subsequent Event [Member]
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Jun. 30, 2013
Claimed Manufacturing Exemptions And Credits [Member]
Ameren Illinois Company [Member]
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Loss Contingencies [Line Items] | ||||||||||
Average number of total defendants named | 80 | |||||||||
Asbestos-related lawsuits were pending | 90 | [1] | 58 | 68 | 2 | |||||
Range of possible loss, minimum | $ 16.0 | $ 7.0 | $ 9.0 | $ 0.5 | ||||||
Range of possible loss maximum | 4.0 | |||||||||
Loss contingency accrual | 0.5 | |||||||||
Percent of allowed cash expenditures in excess of base rates to be recovered through charges assessed to customers | 90.00% | |||||||||
Asbestos trust fund balance | 23 | |||||||||
Percent of difference to be contributed to the asbestos trust fund if cash expenditures are less than amount included in base electric rates. | 90.00% | |||||||||
Public Utilities, Number of Customers | 2,400 | |||||||||
Loss Contingency, Damages Awarded, Value | 4 | |||||||||
Gain (Loss) Related to Litigation Settlement | $ 7 | |||||||||
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Summary Of Significant Accounting Policies (Schedule Of Excise Taxes) (Detail) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2013
|
Jun. 30, 2012
|
Jun. 30, 2013
|
Jun. 30, 2012
|
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Accounting Policies [Line Items] | ||||
Excise tax expense | $ 49 | $ 48 | $ 104 | $ 93 |
Ameren Missouri [Member]
|
||||
Accounting Policies [Line Items] | ||||
Excise tax expense | 38 | 38 | 71 | 65 |
Ameren Illinois Company [Member]
|
||||
Accounting Policies [Line Items] | ||||
Excise tax expense | $ 11 | $ 10 | $ 33 | $ 28 |
Commitments And Contingencies (Pumped-Storage Hydroelectric Facility Breach) (Detail) (Ameren Missouri [Member], USD $)
In Millions, unless otherwise specified |
Jun. 30, 2013
|
---|---|
Ameren Missouri [Member]
|
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Loss Contingencies [Line Items] | |
Insurance settlements receivable | $ 68 |
Derivative Financial Instruments (Narrative) (Detail) (Ameren Missouri [Member], USD $)
In Millions, unless otherwise specified |
Dec. 31, 2012
|
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Ameren Missouri [Member]
|
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Derivative [Line Items] | |
Counterparty letters of credit held as collateral | $ 1 |