Missouri | 1-14756 | 43-1723446 |
(State of other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification Number) |
(d) | Exhibits |
Exhibit Number: | Title: |
12.1 | Computation of Ratio of Earnings to Fixed Charges |
23.1 | Consent of PricewaterhouseCoopers LLP |
99.1 | Item 6. Selected Financial Data |
99.2 | Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations |
99.3 | Item 7A. Quantitative and Qualitative Disclosures about Market Risk |
99.4 | Item 8. Financial Statements and Supplementary Data |
99.5 | Schedule I. Condensed Financial Information of Parent |
99.6 | Schedule II. Valuation and Qualifying Accounts |
101.INS | XBRL Instance Document |
101.SCH | XBRL Taxonomy Extension Schema Document |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
101.DEF | XBRL Taxonomy Extension Definition Document |
• | 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 the Federal Energy Regulatory Commission (“FERC”), the Federal Communications Commission 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 fuel adjustment clause prudence review by the Missouri Public Service Commission; 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 Illinois Energy Infrastructure Modernization Act (“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; |
• | the decision of when Ameren Illinois would begin 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 business at both the state and federal levels, and the implementation of deregulation; |
• | 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, coal combustion residuals, 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. |
Exhibit Number: | Title: |
12.1 | Computation of Ratio of Earnings to Fixed Charges |
23.1 | Consent of PricewaterhouseCoopers LLP |
99.1 | Item 6. Selected Financial Data |
99.2 | Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations |
99.3 | Item 7A. Quantitative and Qualitative Disclosures about Market Risk |
99.4 | Item 8. Financial Statements and Supplementary Data |
99.5 | Schedule I. Condensed Financial Information of Parent |
99.6 | Schedule II. Valuation and Qualifying Accounts |
101.INS | XBRL Instance Document |
101.SCH | XBRL Taxonomy Extension Schema Document |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document |
101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
101.DEF | XBRL Taxonomy Extension Definition Document |
Year Ended December 31, | ||||||||||||||||||||
2008 | 2009 | 2010 | (a) | 2011 | (b) | 2012 | ||||||||||||||
Earnings available for fixed charges, as defined: | ||||||||||||||||||||
Net income from continuing operations attributable to Ameren Corporation | $ | 181,189 | $ | 367,827 | $ | 483,414 | $ | 417,596 | $ | 517,398 | ||||||||||
Tax expense (benefit) based on income | 128,160 | 154,369 | 273,927 | 245,191 | 308,590 | |||||||||||||||
Fixed charges excluding preferred stock dividends tax adjustment (c) | 393,395 | 465,523 | 458,490 | 427,593 | 422,264 | |||||||||||||||
Earnings available for fixed charges, as defined | $ | 702,744 | $ | 987,719 | $ | 1,215,831 | $ | 1,090,380 | $ | 1,248,252 | ||||||||||
Fixed charges, as defined: | ||||||||||||||||||||
Interest expense on short-term and long-term debt (c) | $ | 359,414 | $ | 427,663 | $ | 426,666 | $ | 397,618 | $ | 389,496 | ||||||||||
Estimated interest cost within rental expense | 5,331 | 7,211 | 7,476 | 7,193 | 7,024 | |||||||||||||||
Amortization of net debt premium, discount, and expenses | 18,293 | 20,775 | 16,070 | 16,754 | 19,301 | |||||||||||||||
Subsidiary preferred stock dividends | 10,357 | 9,874 | 8,278 | 6,028 | 6,443 | |||||||||||||||
Adjust preferred stock dividends to pretax basis | 6,989 | 6,279 | 4,942 | 3,859 | 4,032 | |||||||||||||||
Total fixed charges, as defined | $ | 400,384 | $ | 471,802 | $ | 463,432 | $ | 431,452 | $ | 426,296 | ||||||||||
Consolidated ratio of earnings to fixed charges | 1.76 | 2.09 | 2.62 | 2.53 | 2.93 |
(a) | In 2010, Ameren Corporation recorded an impairment charge of $64 million related to the Meredosia energy center. See Note 17 - Impairment and Other Charges under Exhibit 99.4, Item 8 of this current report on Form 8-K for additional information. |
(b) | In 2011, Ameren Corporation recorded a charge to earnings of $123 million related to an Ameren Missouri loss on regulatory disallowance and charges related to the closure of the Meredosia and Hutsonville energy centers. See Note 17 - Impairment and Other Charges under Exhibit 99.4, Item 8 of this current report on Form 8-K for additional information. |
(c) | Includes interest expense related to uncertain tax positions. |
For the years ended December 31, (In millions, except per share amounts) | 2012 | 2011 | 2010 | 2009 | 2008 | ||||||||||||||
Operating revenues | $ | 5,781 | $ | 6,227 | $ | 6,269 | $ | 5,904 | $ | 6,512 | |||||||||
Operating income | 1,191 | 1,011 | 1,125 | 911 | 685 | ||||||||||||||
Income from continuing operations | 524 | 424 | 492 | 382 | 248 | ||||||||||||||
Net income (loss) attributable to Ameren Corporation | (974 | ) | 519 | 139 | 612 | 605 | |||||||||||||
Common stock dividends | 382 | 375 | 368 | 338 | 534 | ||||||||||||||
Continuing operations earnings per share - basic and diluted | 2.13 | 1.73 | 2.02 | 1.67 | 0.86 | ||||||||||||||
Common stock dividends per share | 1.60 | 1.555 | 1.54 | 1.54 | 2.54 | ||||||||||||||
As of December 31: | |||||||||||||||||||
Total assets(a) | $ | 22,219 | $ | 23,723 | $ | 23,511 | $ | 23,702 | $ | 22,671 | |||||||||
Long-term debt, excluding current maturities(b) | 5,802 | 5,853 | 6,030 | 6,287 | 5,523 | ||||||||||||||
Total Ameren Corporation stockholders’ equity | 6,616 | 7,919 | 7,730 | 7,856 | 6,963 |
(a) | Includes total assets from discontinued operations of $1,600 million, $3,718 million, $3,788 million, $4,484 million, and $4,521 million at December 31, 2012, 2011, 2010, 2009 and 2008, respectively. |
(b) | Excludes long-term debt from discontinued operations. |
• | Ameren Missouri operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution |
• | 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, Marketing Company, and through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information regarding that presentation. |
• | the absence in 2012 of charges recorded in 2011 for the MoPSC's July 2011 disallowance of costs of enhancements relating to the rebuilding of Ameren Missouri's Taum Sauk energy center in excess of amounts recovered from property insurance and for the closure of the Meredosia and Hutsonville energy centers (32 cents per share); |
• | higher utility rates at Ameren Missouri and Ameren Illinois. Ameren Missouri's electric rates increased pursuant to an order issued by the MoPSC, which became effective in July 2011. The favorable impact of the Ameren Missouri rate increase on earnings was reduced by the increased regulatory asset amortization directed by the rate order. Ameren Illinois' natural gas rates increased pursuant to an order issued by the ICC, which became effective in mid-January 2012 (22 cents per share); |
• | the absence in 2012 of a Callaway energy center refueling and maintenance outage (11 cents per share); |
• | the impact of fewer major storms on operations and |
• | a reduction in Ameren Missouri's purchased power expense and an increase in interest income, each as a result of a FERC-ordered refund received in 2012 from Entergy for a power purchase agreement that expired in 2009 (7 cents per share); |
• | the absence in 2012 of a 2011 charge associated with voluntary separation offers to eligible Ameren Missouri and Ameren Services employees (7 cents per share); |
• | the absence in 2012 of a reduction in Ameren Missouri's revenues as a result of the MoPSC's April 2011 FAC prudence review order covering the period from March 1, 2009, to September 30, 2009, which resulted in Ameren Missouri recording an obligation to refund to its electric customers the earnings associated with certain previously recognized sales (5 cents per share); and |
• | reduction in operations and maintenance expenses at Ameren Missouri energy centers due to fewer outages and a reduction in employees (2 cents per share). |
• | a reduction in Ameren Illinois' electric earnings primarily caused by a lower allowed return on equity under electric delivery service formula ratemaking and required donations pursuant to the IEIMA (17 cents per share); |
• | an increase in Ameren Missouri depreciation and amortization expense caused primarily by the installation of scrubbers at the Sioux energy center (8 cents per share); |
• | reduced electric and natural gas demand as a result of warmer 2012 winter temperatures (estimated at 7 cents per share); |
• | the absence of margin from the Meredosia and Hutsonville energy centers due to their closure in 2011, partially offset by a reduction in depreciation expense related to these energy centers, including a 2011 change in estimate related to asset retirement obligations (7 cents per share); and |
• | reduced rate-regulated retail sales volumes, excluding the effects of abnormal weather, as sales volumes declined due to continued economic pressure, energy efficiency measures, and customer conservation efforts, among other items (2 cents per share). |
• | a charge to earnings related to the MoPSC’s July 2011 disallowance of costs of enhancements relating to the rebuilding of the Taum Sauk energy center in excess of amounts recovered from property insurance (23 cents per share); |
• | reduced rate-regulated retail sales volumes, excluding the effects of abnormal weather, as sales volumes declined due to continued economic pressure, energy efficiency measures, and customer conservation efforts as well as lower wholesale sales at Ameren Missouri due to a reduction in customers and the expiration of favorably priced contracts, among other items (15 cents per share); |
• | the impact of weather conditions on electric and natural gas demand (estimated at 10 cents per share); |
• | increased operations and maintenance expenses as a result of major storms in 2011 (9 cents per share); |
• | a reduction in allowance for equity funds used during construction reflecting the 2010 completion of two scrubbers at Ameren Missouri’s Sioux energy center (8 cents per share); |
• | reduced income tax benefit driven by reduced impairment charges relating to the Meredosia and Hutsonville energy centers, depreciation and interest charges (8 cents per share); |
• | increased operations and maintenance expenses associated with voluntary separation offers to eligible Ameren Missouri and Ameren Services employees during 2011 (7 cents per share); |
• | a reduction in revenues resulting from the MoPSC’s April 2011 order with respect to its FAC review for the period from March 1, 2009, to September 30, 2009, as discussed above. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information (5 cents per share); and |
• | an increase in depreciation and amortization expense caused primarily by the installation of scrubbers at Ameren Missouri’s Sioux energy center as well as other capital additions (4 cents per share). |
• | higher Ameren Missouri electric rates pursuant to orders issued by the MoPSC, which became effective in June 2010 and in July 2011, as well as higher Ameren Missouri natural gas rates pursuant to a MoPSC order, which became effective in late February 2011. The impact of the Ameren Missouri electric rate increases on earnings was reduced by the adoption of life span depreciation methodology, recognition in 2010 of regulatory assets for previously expensed costs in the prior-year period, and increased regulatory asset amortization as directed by the rate orders (17 cents per share). These amounts exclude the unfavorable impact of the charge to earnings related to the MoPSC’s disallowance of Taum Sauk rebuilding costs discussed above; |
• | lower interest expense, primarily due to the redemption of $66 million of Ameren Missouri’s subordinated deferrable interest debentures in September 2010, Ameren Illinois’ redemptions of $150 million of senior secured notes and $40 million of first mortgage bonds in June 2011 and September 2010, respectively, and a reduction in borrowings under credit facility agreements (7 cents per share); |
• | reduced impairment and other charges (7 cents per share); |
• | higher Ameren Illinois electric rates pursuant to orders issued by the ICC in 2010 (6 cents per share); |
• | the absence in 2011 of a charge for the impact on deferred taxes from changes in federal health care laws (6 cents per share); |
• | the absence in 2011 of charges recorded in 2010 for cancelled or unrecoverable projects at Ameren Missouri (6 cents per share); |
• | a reduction in Ameren Missouri operations and maintenance expense related to plant maintenance as fewer costs were |
• | reduction in expense as a result of disciplined cost management efforts to align spending with regulatory outcomes and economic conditions. |
2012 | Ameren Missouri | Ameren Illinois | Other / Intersegment Eliminations | Total | |||||||||||
Electric margins | $ | 2,340 | $ | 1,034 | $ | (11 | ) | $ | 3,363 | ||||||
Natural gas margins | 75 | 378 | (1 | ) | 452 | ||||||||||
Other revenues | 1 | — | (1 | ) | — | ||||||||||
Other operations and maintenance | (827 | ) | (684 | ) | (3 | ) | (1,514 | ) | |||||||
Impairment and other charges | — | — | — | — | |||||||||||
Depreciation and amortization | (440 | ) | (221 | ) | (6 | ) | (667 | ) | |||||||
Taxes other than income taxes | (304 | ) | (130 | ) | (9 | ) | (443 | ) | |||||||
Other income and (expenses) | 49 | (10 | ) | (6 | ) | 33 | |||||||||
Interest charges | (223 | ) | (129 | ) | (39 | ) | (391 | ) | |||||||
Income (taxes) benefit | (252 | ) | (94 | ) | 37 | (309 | ) | ||||||||
Income (loss) from continuing operations | 419 | 144 | (39 | ) | 524 | ||||||||||
Loss from discontinued operations, net of taxes | — | — | (1,498 | ) | (1,498 | ) | |||||||||
Net income (loss) | 419 | 144 | (1,537 | ) | (974 | ) | |||||||||
Net income (loss) attributable to noncontrolling interests - continuing operations | (3 | ) | (3 | ) | — | (6 | ) | ||||||||
Net income (loss) attributable to noncontrolling interests - discontinued operations | — | — | 6 | 6 | |||||||||||
Net income (loss) attributable to Ameren Corporation | $ | 416 | $ | 141 | $ | (1,531 | ) | $ | (974 | ) | |||||
2011 | |||||||||||||||
Electric margins | $ | 2,252 | $ | 1,087 | $ | 24 | $ | 3,363 | |||||||
Natural gas margins | 79 | 354 | (2 | ) | 431 | ||||||||||
Other revenues | 5 | 1 | (6 | ) | — | ||||||||||
Other operations and maintenance | (934 | ) | (640 | ) | (6 | ) | (1,580 | ) | |||||||
Impairment and other charges | (89 | ) | — | (34 | ) | (123 | ) | ||||||||
Depreciation and amortization | (408 | ) | (215 | ) | (23 | ) | (646 | ) | |||||||
Taxes other than income taxes | (296 | ) | (129 | ) | (9 | ) | (434 | ) | |||||||
Other income and (expenses) | 51 | 1 | (7 | ) | 45 | ||||||||||
Interest charges | (209 | ) | (136 | ) | (42 | ) | (387 | ) | |||||||
Income (taxes) benefit | (161 | ) | (127 | ) | 43 | (245 | ) | ||||||||
Income (loss) from continuing operations | 290 | 196 | (62 | ) | 424 | ||||||||||
Income from discontinued operations, net of taxes | — | — | 102 | 102 | |||||||||||
Net income | 290 | 196 | 40 | 526 | |||||||||||
Net income (loss) attributable to noncontrolling interests - continuing operations | (3 | ) | (3 | ) | — | (6 | ) | ||||||||
Net income (loss) attributable to noncontrolling interests - discontinued operations | — | — | (1 | ) | (1 | ) | |||||||||
Net income attributable to Ameren Corporation | $ | 287 | $ | 193 | $ | 39 | $ | 519 | |||||||
2010 | |||||||||||||||
Electric margins | $ | 2,233 | $ | 1,096 | $ | 29 | $ | 3,358 | |||||||
Natural gas margins | 75 | 375 | (2 | ) | 448 | ||||||||||
Other revenues | 1 | — | (1 | ) | — | ||||||||||
Other operations and maintenance | (931 | ) | (635 | ) | — | (1,566 | ) | ||||||||
Impairment and other charges | — | — | (64 | ) | (64 | ) | |||||||||
Depreciation and amortization | (382 | ) | (210 | ) | (35 | ) | (627 | ) | |||||||
Taxes other than income taxes | (285 | ) | (128 | ) | (11 | ) | (424 | ) | |||||||
Other income and (expenses) | 70 | (6 | ) | (8 | ) | 56 | |||||||||
Interest charges | (213 | ) | (143 | ) | (59 | ) | (415 | ) | |||||||
Income (taxes) benefit | (199 | ) | (137 | ) | 62 | (274 | ) | ||||||||
Income (loss) from continuing operations | 369 | 212 | (89 | ) | 492 | ||||||||||
Loss from discontinued operations, net of taxes | — | — | (341 | ) | (341 | ) | |||||||||
Net income (loss) | 369 | 212 | (430 | ) | 151 | ||||||||||
Net income (loss) attributable to noncontrolling interests - continuing operations | (5 | ) | (4 | ) | — | (9 | ) | ||||||||
Net income (loss) attributable to noncontrolling interests - discontinued operations | — | — | (3 | ) | (3 | ) | |||||||||
Net income (loss) attributable to Ameren Corporation | $ | 364 | $ | 208 | $ | (433 | ) | $ | 139 |
2012 versus 2011 | Ameren Missouri Segment | Ameren Illinois Segment | Other(a) | Ameren | |||||||||||
Electric revenue change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | (19 | ) | $ | (1 | ) | $ | — | $ | (20 | ) | ||||
Regulated rates: | |||||||||||||||
Base rates (estimate) | 102 | — | — | 102 | |||||||||||
Formula ratemaking adjustment under IEIMA (estimate) | — | (55 | ) | — | (55 | ) | |||||||||
Recovery of FAC under-recovery(c) | (47 | ) | — | — | (47 | ) | |||||||||
Off-system revenues (included in base rates) | (131 | ) | — | — | (131 | ) | |||||||||
FAC prudence review disallowance | 17 | — | — | 17 | |||||||||||
Transmission services | 5 | (1 | ) | 1 | 5 | ||||||||||
Wholesale revenues | (13 | ) | (6 | ) | — | (19 | ) | ||||||||
Illinois pass-through power supply costs | — | (154 | ) | 2 | (152 | ) | |||||||||
Energy efficiency programs and environmental remediation cost riders | — | 11 | — | 11 | |||||||||||
Bad debt rider | — | (4 | ) | — | (4 | ) | |||||||||
Hurricane Sandy relief cost recovery | 7 | 10 | — | 17 | |||||||||||
Rate-regulated sales volume (excluding the impact of abnormal weather) | (6 | ) | (3 | ) | — | (9 | ) | ||||||||
Meredosia and Hutsonville energy centers | — | — | (81 | ) | (81 | ) | |||||||||
Other | (5 | ) | 2 | — | (3 | ) | |||||||||
Total electric revenue change | $ | (90 | ) | $ | (201 | ) | $ | (78 | ) | $ | (369 | ) | |||
Fuel and purchased power change: | |||||||||||||||
Fuel: | |||||||||||||||
Meredosia and Hutsonville energy centers | $ | — | $ | — | $ | 45 | $ | 45 | |||||||
Fuel, purchased power and transportation costs (included in base rates) | 106 | — | — | 106 | |||||||||||
Recovery of FAC under-recovery(c) | 47 | — | — | 47 | |||||||||||
Net unrealized MTM gains (losses) | 1 | — | — | 1 | |||||||||||
Power purchase agreement settlement | 24 | — | — | 24 | |||||||||||
Transmission over-recovery | — | (6 | ) | — | (6 | ) | |||||||||
Illinois pass-through power supply costs | — | 154 | (2 | ) | 152 | ||||||||||
Total fuel and purchased power change | $ | 178 | $ | 148 | $ | 43 | $ | 369 | |||||||
Net change in electric margins | $ | 88 | $ | (53 | ) | $ | (35 | ) | $ | — | |||||
Natural gas margins change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | (2 | ) | $ | (10 | ) | $ | — | $ | (12 | ) | ||||
Base rates (estimate) | 2 | 20 | — | 22 | |||||||||||
Rate redesign | (5 | ) | — | — | (5 | ) | |||||||||
Energy efficiency programs and environmental remediation cost riders | — | 8 | — | 8 | |||||||||||
Bad debt rider | — | (5 | ) | — | (5 | ) | |||||||||
Hurricane Sandy relief cost recovery | — | 3 | — | 3 | |||||||||||
Sales volume (excluding impact of abnormal weather) and other | 1 | 8 | 1 | 10 | |||||||||||
Net change in natural gas margins | $ | (4 | ) | $ | 24 | $ | 1 | $ | 21 |
2011 versus 2010 | Ameren Missouri Segment | Ameren Illinois Segment | Other(a) | Ameren | |||||||||||
Electric revenue change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | (29 | ) | $ | (7 | ) | $ | — | $ | (36 | ) | ||||
Regulated rates: | |||||||||||||||
Base rates (estimate) | 172 | 20 | — | 192 | |||||||||||
Recovery of FAC under-recovery(c) | 89 | — | — | 89 | |||||||||||
Off-system revenues included in base rates | 53 | — | — | 53 | |||||||||||
FAC prudence review disallowance | (17 | ) | — | — | (17 | ) | |||||||||
Transmission services | 1 | (4 | ) | 4 | 1 | ||||||||||
Wholesale revenues | (43 | ) | 9 | — | (34 | ) | |||||||||
Illinois pass-through power supply costs | — | (112 | ) | — | (112 | ) | |||||||||
Energy efficiency programs and environmental remediation cost riders | — | 6 | — | 6 | |||||||||||
Bad debt rider | — | (17 | ) | (17 | ) | ||||||||||
Rate-regulated sales volume (excluding the impact of abnormal weather) | (37 | ) | (15 | ) | — | (52 | ) | ||||||||
Net unrealized MTM losses | (2 | ) | — | — | (2 | ) | |||||||||
Meredosia and Hutsonville energy centers | — | — | (2 | ) | (2 | ) | |||||||||
Other | 5 | (1 | ) | — | 4 | ||||||||||
Total electric revenue change | $ | 192 | $ | (121 | ) | $ | 2 | $ | 73 | ||||||
Fuel and purchased power change: | |||||||||||||||
Fuel: | |||||||||||||||
Meredosia and Hutsonville energy centers | $ | — | $ | — | $ | (7 | ) | $ | (7 | ) | |||||
Fuel, purchased power and transportation costs included in base rates | (84 | ) | — | — | (84 | ) | |||||||||
Recovery of FAC under-recovery(c) | (89 | ) | — | — | (89 | ) | |||||||||
Illinois pass-through power supply costs | — | 112 | — | 112 | |||||||||||
Total fuel and purchased power change | $ | (173 | ) | $ | 112 | $ | (7 | ) | $ | (68 | ) | ||||
Net change in electric margins | $ | 19 | $ | (9 | ) | $ | (5 | ) | $ | 5 | |||||
Natural gas margins change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | (1 | ) | $ | (5 | ) | $ | — | $ | (6 | ) | ||||
Bad debt rider | — | (14 | ) | — | (14 | ) | |||||||||
Base rates (estimate) | 5 | 3 | — | 8 | |||||||||||
Energy efficiency programs and environmental remediation cost riders | — | (1 | ) | — | (1 | ) | |||||||||
Sales volume (excluding impact of abnormal weather) and other | — | (4 | ) | — | (4 | ) | |||||||||
Net change in natural gas margins | $ | 4 | $ | (21 | ) | $ | — | $ | (17 | ) |
(a) | Primarily includes amounts for the Meredosia and Hutsonville energy centers, ATXI, and intercompany eliminations. |
(b) | Represents the estimated margin impact of changes in cooling and heating degree-days on electric and natural gas demand compared with the prior year 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 the amortization of a previously recorded regulatory asset. |
• | Higher electric base rates, effective July 2011, which increased revenues by $102 million, offset by an increase in net base fuel expense of $25 million, which was a result of higher net base fuel cost rates approved in the 2011 MoPSC rate order. The change in net base fuel expense was the sum of the change in fuel, purchased power and transportation costs included in base rates (+$106 million) and the change in off-system revenues (-$131 million) in the above table. |
• | Reduced purchased power expense as a result of a FERC-ordered refund received from Entergy in 2012 relating to a power purchase agreement that expired in 2009, which increased margins by $24 million. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this |
• | Absence in 2012 of a reduction in revenues recorded in 2011 resulting from the MoPSC's FAC prudence review order the period from March 1, 2009, to September 30, 2009, which increased revenues by $17 million. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information. |
• | Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy power restoration, which increased revenues by $7 million and was fully offset by operations and maintenance costs with no overall impact on net income. |
• | Higher transmission services revenues primarily due to two transmission projects that went into service in second half of 2011 and were included in transmission rates in 2012, which increased revenues by $5 million. |
• | Summer weather conditions in 2012 were comparable to 2011, as evidenced by an increase of 1% in cooling degree-days. However, weather conditions in Ameren Missouri's service territory in 2012 were the warmest on record with 25% more cooling degree-days than normal. |
• | Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a 16% decrease in heating degree-days, which decreased revenues by $19 million. |
• | The inclusion of wholesale sales in the FAC as an offset to fuel costs beginning July 31, 2011, decreased revenues by $13 million. |
• | Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes that declined by 1%, partially attributable to energy efficiency measures and customer conservation efforts, which decreased revenues by $6 million. |
• | Rate redesign, as a result of the natural gas delivery service rate order that became effective in late February 2011, allowed Ameren Missouri to recover more of its non-PGA residential revenues through a fixed monthly charge, with the remaining amounts recovered based on sales volumes, which resulted in revenues being recovered more evenly throughout the year. Revenues decreased by $5 million, because the rate redesign was not in effect for the first two months of 2011. |
• | Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by decrease in heating degree-days of 16%, which decreased margins by $2 million. |
• | The formula ratemaking adjustment related to an annual reconciliation of the revenue requirement pursuant to the IEIMA decreased revenues by $55 million. The reduction in revenues for 2012 was primarily caused by a lower allowed return on equity as the ICC's 2010 electric rate order resulted in a higher return on equity than the 2012 formula rate calculation allowed. The 2012 formula for the return on equity is equal to the 2012 average of monthly yields of 30-year United States treasury bonds plus 590 basis points. The return on equity included in Ameren Illinois' 2010 electric rate order was 10.2% whereas the 2012 IEIMA formula resulted in an 8.8% return on equity with the ability to earn above or below this amount by 50 basis points. The 2012 revenue requirement reconciliation included the impact of the September ICC order, which reduced revenues from October through December 2012 by $8 million. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information. |
• | Lower wholesale distribution revenues, primarily due to lower demand, and the recognition of a reserve for revenues subject to a refund as a result of a November 2012 FERC administrative law judge's decision, which in total decreased revenues by $6 million. See Note 2 - Rate and Regulatory |
• | Ameren Illinois accrues, as a regulatory asset or liability, transmission costs that are greater than or less than the amount set in transmission rates (transmission under-recovery or over-recovery). In 2012, Ameren Illinois over-recovered from customers its transmission costs by $6 million. As a result, Ameren Illinois reduced a previously recognized regulatory asset that had been established for an under-recovery of costs. |
• | Decreased recoveries through Ameren Illinois' bad debt rider, which decreased margins by $4 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense. |
• | Excluding the estimated impact of abnormal weather, rate-regulated sales volumes that increased by 1%, driven largely by the lower-margin industrial sector; however, margins decreased $3 million due to volume declines in the higher-margin residential and commercial sectors, partially attributable to energy efficiency measures and customer conservation efforts. |
• | Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a decrease of 14% in heating degree-days, which decreased revenues by $1 million. |
• | Increased recovery of energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $11 million. See Other Operations and Maintenance Expenses in this section for information on the related offsetting increase in energy efficiency and environmental remediation costs. |
• | Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy power restoration, which increased revenues by $10 million, and was fully offset by operations and maintenance costs with no overall impact on net income. |
• | Summer weather conditions in 2012 were comparable to 2011, as evidenced by an increase of 2% in cooling degree-days. However, weather conditions in Ameren Illinois' service territory in 2012 were the warmest on record with 24% more cooling degree-days than normal. |
• | Increase in natural gas rates effective January 2012, which increased revenues by $20 million. |
• | Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois cost recovery mechanisms, which increased revenues by $8 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs. |
• | Higher sales volume and other primarily due to increased transportation sales from two large industrial customers and 1% higher residential sales volumes, excluding the impact of abnormal weather, which combined increased margins by $8 million. |
• | Recovery of labor and benefit costs associated with crews assisting with Hurricane Sandy gas service restoration, which increased revenues by $3 million, and was fully offset by operations and maintenance costs, with no overall impact on net income. |
• | Winter weather conditions in 2012 were mild compared to near normal conditions in 2011, as evidenced by a decrease in heating degree-days of 14%, which decreased margins $10 million. |
• | Decreased recoveries through Ameren Illinois' bad debt rider, which reduced margins by $5 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense. |
• | Lower wholesale sales due to a reduction in customers, the |
• | Excluding the estimated impact of abnormal weather, rate-regulated retail sales volumes declined by 1%, attributable to continued economic pressure, energy efficiency measures, and customer conservation efforts, which decreased revenues by $37 million. |
• | Winter weather conditions in 2011 were near normal compared to a somewhat colder-than-normal 2010, as evidenced by a 7% decrease in heating degree-days, which decreased revenues by $29 million. |
• | A $17 million reduction in revenues recorded in 2011 resulting from the MoPSC's order with respect to its FAC disallowance for the period from March 1, 2009 to September 30, 2009. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information regarding the FAC prudence review. |
• | Decreased recovery of prior years' bad debt expense through the Illinois bad debt rider, effective March 2010, which decreased margins by $17 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense. |
• | Continued economic pressure, energy efficiency measures, and customer conservation efforts, which decreased revenues by $15 million. |
• | Winter weather conditions in 2011 were near normal compared to a somewhat colder-than-normal 2010, as evidenced by a 5% decrease in heating degree-days, which decreased revenues by $7 million. |
• | Higher electric delivery service rates, effective in May and November 2010, which increased margins by $20 million. |
• | Higher wholesale revenues, primarily due to higher rates effective April 2011, which increased revenues by $9 million. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for further information. |
• | Increased recovery of energy efficiency program costs and environmental remediation costs through Illinois rate-adjustment mechanisms, which increased margins by $6 million. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency and environmental remediation costs. |
• | Decreased recovery of prior years' bad debt expense under the Illinois bad debt rider, effective March 2010, which decreased margins by $14 million. See Other Operations and Maintenance Expenses in this section for additional information on a related offsetting decrease in bad debt expense. |
• | Unfavorable winter weather conditions, as evidenced by a 5% decrease in heating degree-days, decreased revenues by $5 million. However, compared to normal, Ameren Illinois experienced in 2011 a 2% decrease in heating degree-days. |
• | Native load sales volumes declined by 4%, excluding the estimated impact of abnormal weather, largely in the commercial and industrial sectors, attributable to continued economic pressure, which decreased revenues by $4 million. |
• | A $40 million decrease in Callaway energy center refueling and maintenance costs as there was no outage in 2012. |
• | A $27 million decrease in employee severance costs due to the voluntary separation program in 2011. |
• | A $25 million reduction in other labor costs, primarily because of staff reductions. |
• | A $19 million decrease in storm-related repair costs, due to fewer major storms in 2012. |
• | A $6 million favorable change in unrealized net MTM gains between years, resulting from changes in the market value of investments used to support Ameren's deferred compensation plans. |
• | A $6 million decrease in bad debt expense due to improved customer collections. |
• | A $4 million decrease in non-storm-related distribution maintenance expenditures, primarily due to lower repair spending. |
• | Disciplined cost management efforts to align spending with regulatory outcomes, policies, and economic conditions. |
• | A $19 million increase in energy efficiency and environmental remediation costs. |
• | A $16 million increase in non-storm-related electric distribution maintenance expenditures due, in part, to mild winter weather in 2012 allowing crews to complete more maintenance projects. |
• | A $15 million increase in other labor costs, primarily because of staff additions due to the requirements of the IEIMA. |
• | An $11 million increase in transmission and distribution expenses, primarily because of National Electric Safety Code repairs, which are nonrecoverable operating expenditures under formula ratemaking pursuant to the IEIMA, and pipeline integration compliance. |
• | A $6 million increase in employee benefit costs, primarily due to increased pension expense. |
• | A $14 million decrease in storm-related repair costs, due to fewer major storms in 2012. |
• | A $9 million decrease in bad debt expense, including $5 million due to improved customer collections and $4 million due to adjustments related to prior years under the bad debt rider. Expenses recorded under the Ameren Illinois bad debt rider mechanism were recovered through customer billings, and so were offset by increased revenues, with no overall effect on net income. |
• | Recognition of $27 million of employee severance costs related to the voluntary separation plan in 2011. |
• | A $21 million increase in storm-related repair costs, due to major storms in 2011. |
• | A reduction in other operations and maintenance expenses in 2010 by $11 million for the May 2010 MoPSC rate order, which resulted in the recording of regulatory assets related to 2009 employee severance costs and storm costs. |
• | An unfavorable change of $5 million in unrealized net MTM adjustments between years, resulting from changes in the market value of investments used to support Ameren's deferred compensation plans. |
• | Plant maintenance costs decreased by $23 million, primarily because the scope of the outages in 2011 was not as extensive as in 2010. Costs associated with the 2011 refueling and maintenance outage at Ameren Missouri's Callaway energy center were consistent with costs incurred for the 2010 refueling and maintenance outage. |
• | Charges in 2010 of $22 million because of canceled or unrecoverable projects that did not recur in 2011. |
• | A $9 million decrease in employee benefit costs, primarily because of adjustments under the pension and postretirement benefit cost tracker. |
• | Disciplined cost management efforts to align spending with regulatory outcomes and economic conditions. |
• | A $13 million increase in storm-related repair costs, due to major storms in 2011. |
• | Energy efficiency and environmental remediation costs increased by $5 million. |
• | Injuries and damages expenses were higher by $4 million because of increased claims. |
• | Expenses of $3 million associated with the electric rate case in 2011 were written-off because the rate case was withdrawn after passage of the IEIMA. |
• | A reduction in other operations and maintenance expenses in 2010 of $3 million for a May 2010 ICC rate order, which resulted in the recording of a regulatory asset related to 2009 employee severance costs. |
• | A $19 million reduction in bad debt expense. Adjustments of $31 million under the bad debt rider mechanism were partially offset by higher uncollectible expense. |
• | A reduction of $5 million in non-storm-related distribution maintenance expenditures due, in part, to cost management efforts. |
2012 | 2011 | 2010 | |
Ameren | 37% | 37% | 36% |
Ameren Missouri | 37% | 36% | 35% |
Ameren Illinois | 40% | 39% | 39% |
Net Cash Provided By Operating Activities | Net Cash (Used In) Investing Activities | Net Cash (Used In) Financing Activities | |||||||||||||||||||||||||||||||||
2012 | 2011 | 2010 | 2012 | 2011 | 2010 | 2012 | 2011 | 2010 | |||||||||||||||||||||||||||
Continuing operations | $ | 1,399 | $ | 1,512 | $ | 1,403 | $ | (1,153 | ) | $ | (949 | ) | $ | (1,015 | ) | $ | (426 | ) | $ | (1,020 | ) | $ | (698 | ) | |||||||||||
Discontinued operations | 291 | 366 | 420 | (157 | ) | (99 | ) | (81 | ) | — | (100 | ) | (106 | ) |
• | Cash flows associated with Ameren Missouri's under-recovered FAC costs, which decreased by $161 million. Recoveries outpaced deferrals in 2011 by $87 million, while deferrals outpaced recoveries in 2012 by $74 million. |
• | The premiums paid to debt holders in connection with the repurchase of multiple series of Ameren Missouri and Ameren Illinois senior secured notes totaled $138 million. See Note 5 - Long-term Debt and Equity Financings under |
• | An $82 million decrease in cash collections from customer receivables, excluding the impacts of the receipt of funds from, and deposits into, court registries discussed separately below, primarily caused by milder weather in December 2011, compared with December 2010. |
• | Income tax payments related to continuing operations of $8 million in 2012, compared with income tax refunds of $59 million in 2011. The 2011 refund resulted primarily from an IRS settlement, while the 2012 payment was caused by the purchase of state tax credits. Ameren did not make material federal income tax payments in either period because of accelerated deductions authorized by economic stimulus legislation and other deductions. |
• | A $40 million increase in coal inventory at Ameren Missouri primarily due to additional tons held in inventory because generation levels were below expected levels due to market |
• | A $22 million increase in energy efficiency expenditures, primarily for Ameren Illinois customer programs, which are recovered through customer billings over time. |
• | Electric and natural gas margins, as discussed in Results of Operations, which increased by $75 million, excluding impacts of noncash MTM transactions and Ameren Illinois' noncash IEIMA formula ratemaking adjustment. |
• | Ameren Missouri's receipt of $37 million from the Stoddard County Circuit Court's registry and the Cole County Circuit Court's registry as the MoPSC's 2009 and 2010 electric rate orders were upheld on appeals. Additionally, $24 million fewer Ameren Missouri receivables were paid into the court registries in 2012 in connection with the electric rate order appeals. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information. |
• | A $52 million decrease in pension and postretirement plan contributions. In 2011, Ameren Illinois contributed to Ameren's postretirement benefit plan trust an incremental $100 million in excess of Ameren Illinois' annual postretirement net periodic cost for regulatory purposes. |
• | A $50 million decrease in the cost of natural gas held in storage because of lower prices. |
• | A $35 million decrease in major storm restoration costs. |
• | A $26 million decrease in taxes other than income tax payments, primarily related to Ameren Missouri, caused by the timing of property tax payments at each year end, partially offset by higher assessed property tax values. |
• | A $21 million reduction in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center, caused by the absence of a refueling outage in 2012. |
• | A $21 million increase in natural gas commodity over-recovered costs under the PGA, primarily related to Ameren Illinois. |
• | A $20 million decrease in payments related to the MISO liability due, in part, to fewer payments required for December 2011 purchases compared to the payments required for December 2010 purchases. |
• | A net $5 million decrease in collateral posted with counterparties due, in part, to changes in the market prices of power and natural gas and in contracted commodity volumes. |
• | Ameren Missouri’s regulatory asset for FAC under-recovery, which decreased by $216 million as more deferred costs were recovered from customers during 2011. |
• | Trade accounts receivable and unbilled revenues balances at Ameren Missouri and Ameren Illinois decreased, primarily because of milder weather in the fourth quarter of 2011, compared with the fourth quarter of 2010. Those same weather conditions caused accounts payable balances to MISO and natural gas suppliers to decrease as less power and natural gas was purchased. Additionally, during 2011, MISO shortened the length of its settlement terms for all of its members. The new terms resulted in an acceleration of payments that previously would not have been made until 2012. These factors resulted in a net increase of $128 million in cash from operating activities in 2011 compared with 2010. |
• | A net $106 million decrease in collateral posted with counterparties due, in part, to a reduction in the market price of natural gas and in contracted volumes. |
• | A $26 million decrease in interest payments related to continuing operations, primarily due to the long-term debt redemptions and a reduction in Ameren’s borrowings under its credit facility agreements, which resulted in an $11 million reduction in interest payments. |
• | An $11 million reduction in payments for scheduled nuclear refueling and maintenance outages at the Callaway energy center caused primarily by the timing of the 2011 outage compared with the 2010 outage, which had unpaid liabilities as of December 31, 2011. |
• | A $108 million increase in pension and postretirement benefit plan contributions. Ameren Illinois contributed to Ameren’s postretirement benefit VEBA trust an incremental $100 million in excess of Ameren Illinois’ annual postretirement net periodic cost for regulatory purposes. |
• | A $62 million decrease in income tax refunds. The 2010 refund resulted primarily from a 2009 change in tax treatment of electric generation plant expenditures. The 2011 refund resulted primarily from casualty loss deductions due to an Internal Revenue Service audit settlement. Ameren did not make any federal income tax payments in 2011 because of accelerated deductions authorized by economic stimulus legislation, use of its net operating loss carryforwards, and other deductions. |
• | A $55 million decrease associated with the December 2005 Taum Sauk incident, primarily as a result of insurance recoveries received in 2010, but not in 2011. |
• | A $34 million increase in major storm restoration costs. |
• | A $28 million increase in taxes other than income tax |
• | Reduced collections as more utility customers were past due on their bills on December 31, 2011, than on December 31, 2010. Additionally, write-offs of customer receivable balances increased because of economic conditions. |
• | An $18 million increase in Ameren Missouri receivables held in court registries under the appeals of the MoPSC’s 2009 and 2010 rate orders. See Note 2 - Rate and Regulatory Matters under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for additional information. |
• | A $16 million decrease in Ameren Illinois’ electric purchased power commodity over-recovered costs. |
• | A $15 million increase in energy efficiency expenditures for new customer programs. The Ameren Illinois amount is recovered through customer billings over time. |
• | An $11 million decrease in natural gas commodity over-recovered costs under the PGA, primarily in Illinois. |
• | Electric and natural gas margins, as discussed in Results of Operations, which decreased by $10 million, excluding impacts of noncash MTM transactions. |
• | A $7 million increase in preliminary study expenditures, primarily at Ameren Missouri for environmental compliance testing. |
2013 | 2014 - 2017 | Total | |||||||||||||||||
Ameren Missouri | $ | 720 | $ | 2,250 | - | $ | 3,045 | $ | 2,970 | - | $ | 3,765 | |||||||
Ameren Illinois | 695 | 2,400 | - | 3,250 | 3,095 | - | 3,945 | ||||||||||||
ATXI | 60 | 965 | - | 1,310 | 1,025 | - | 1,370 | ||||||||||||
Other(a) | (5 | ) | 60 | - | 80 | 55 | - | 75 | |||||||||||
Ameren | $ | 1,470 | $ | 5,675 | - | $ | 7,685 | $ | 7,145 | - | $ | 9,155 |
(a) | Includes the elimination of intercompany transfers. |
Expiration | Borrowing Capacity | Credit Available | |||||||
2012 Missouri Credit Agreement(a)(b) | November 2017 | $ | 1,000 | $ | 1,000 | ||||
2012 Illinois Credit Agreement(a)(b) | November 2017 | 1,100 | 1,100 | ||||||
Less: Letters of credit | (c) | (9 | ) | ||||||
Total | $ | 2,100 | $ | 2,091 |
(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, as requested by the borrower and approved by the lenders, or for a longer period upon 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 will seek state regulatory approval to extend the maturity date of their borrowing sublimits under the 2012 Credit Agreements to November 14, 2017. |
(c) | Not applicable. |
2012 Missouri Credit Agreement | 2012 Illinois Credit Agreement | ||||||
Ameren | $ | 500 | $ | 300 | |||
Ameren Missouri | 800 | (a) | |||||
Ameren Illinois | (a) | 800 |
(a) | Not applicable. |
Month Issued, Redeemed, Repurchased or Matured | 2012 | 2011 | 2010 | ||||||||||
Issuances | |||||||||||||
Long-term debt | |||||||||||||
Ameren Missouri: | |||||||||||||
3.90% Senior secured notes due 2042 | September | $ | 482 | $ | — | $ | — | ||||||
Ameren Illinois: | |||||||||||||
2.70% Senior secured notes due 2022 | August | 400 | — | — | |||||||||
Total Ameren long-term debt issuances | $ | 882 | $ | — | $ | — | |||||||
Common stock | |||||||||||||
Ameren: | |||||||||||||
DRPlus and 401(k) | Various | $ | — | $ | 65 | $ | 80 | ||||||
Total common stock issuances | $ | — | $ | 65 | $ | 80 | |||||||
Total Ameren long-term debt and common stock issuances | $ | 882 | $ | 65 | $ | 80 | |||||||
Redemptions, Repurchases and Maturities | |||||||||||||
Long-term debt | |||||||||||||
Ameren Missouri: | |||||||||||||
City of Bowling Green capital lease (Peno Creek CT) | Various | $ | 5 | $ | 5 | $ | 4 | ||||||
5.25% Senior secured notes due 2012 | September | 173 | — | — | |||||||||
6.00% Senior secured notes due 2018 | September | 71 | — | — | |||||||||
6.70% Senior secured notes due 2019 | September | 121 | — | — | |||||||||
5.10% Senior secured notes due 2018 | September | 1 | — | — | |||||||||
5.10% Senior secured notes due 2019 | September | 56 | — | — | |||||||||
7.69% Series A subordinated deferrable interest debentures due 2036 | September | — | — | 66 | |||||||||
Ameren Illinois: | |||||||||||||
6.625% Senior secured notes due 2011 | June | — | 150 | — | |||||||||
9.75% Senior secured notes due 2018 | August | 87 | — | — | |||||||||
6.25% Senior secured notes due 2018 | August | 194 | — | — | |||||||||
2000 Series A 5.50% pollution control revenue bonds due 2014 | August | 51 | — | — | |||||||||
7.61% Series 1997-2 first mortgage bonds due 2017 | September | — | — | 40 | |||||||||
6.20% Series 1992B due 2012 | November | 1 | — | — | |||||||||
Total Ameren long-term debt redemptions, repurchases and maturities | $ | 760 | $ | 155 | $ | 110 | |||||||
Preferred stock | |||||||||||||
Ameren Missouri: | |||||||||||||
$7.64 Series | August | $ | — | $ | — | $ | 33 | ||||||
Ameren Illinois: | |||||||||||||
4.50% Series | August | — | — | 11 | |||||||||
4.64% Series | August | — | — | 8 | |||||||||
4.08% Series(a) | September | — | — | 7 | |||||||||
4.20% Series(a) | September | — | — | 5 | |||||||||
4.26% Series(a) | September | — | — | 4 | |||||||||
4.42% Series(a) | September | — | — | 3 | |||||||||
4.70% Series(a) | September | — | — | 5 | |||||||||
7.75% Series(a) | September | — | — | 9 | |||||||||
Total Ameren preferred stock redemptions and repurchases | $ | — | $ | — | $ | 85 | |||||||
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities | $ | 760 | $ | 155 | $ | 195 |
(a) | In September 2010, Ameren contributed to the capital of Ameren Illinois (formerly IP), without the payment of any consideration, all of the IP preferred stock owned by Ameren ($33 million). IP canceled these preferred shares. |
Total | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | After 5 Years | |||||||||||||||
Long-term debt and capital lease obligations(a)(b) | $ | 6,167 | $ | 355 | $ | 654 | $ | 1,076 | $ | 4,082 | |||||||||
Interest payments(c) | 3,688 | 369 | 624 | 546 | 2,149 | ||||||||||||||
Operating leases(d) | 138 | 19 | 28 | 28 | 63 | ||||||||||||||
Other obligations(e) | 7,613 | 1,563 | 2,556 | 1,835 | 1,659 | ||||||||||||||
Total cash contractual obligations | $ | 17,606 | $ | 2,306 | $ | 3,862 | $ | 3,485 | $ | 7,953 |
(a) | Excludes fair-market value adjustments of long-term debt of $4 million. |
(b) | Excludes unamortized discount and premium of $14 million. |
(c) | The weighted-average variable-rate debt has been calculated using the interest rate as of December 31, 2012. |
(d) | Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million for these items is included in the Less than 1 Year, 1 - 3 Years, and 3 - 5 Years columns. |
(e) | See Other Obligations in Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K for discussion of items included herein. |
Moody’s | S&P | Fitch | |
Ameren: | |||
Issuer/corporate credit rating | Baa3 | BBB- | BBB |
Senior unsecured debt | Baa3 | BB+ | BBB |
Commercial paper | P-3 | A-3 | F2 |
Ameren Missouri: | |||
Issuer/corporate credit rating | Baa2 | BBB- | BBB+ |
Secured debt | A3 | BBB+ | A |
Ameren Illinois: | |||
Issuer/corporate credit rating | Baa2 | BBB- | BBB- |
Secured debt | A3 | BBB+ | BBB+ |
Senior unsecured debt | Baa2 | BBB- | BBB |
• | Ameren's strategy for earning competitive returns on its rate-regulated investments involves meeting customer energy needs in an efficient fashion, working to enhance regulatory frameworks, making timely and well-supported rate case filings, and aligning overall spending with those rate case outcomes, economic conditions and return opportunities. |
• | 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. We believe that Ameren Illinois' participation in the performance-based formula ratemaking framework pursuant to the IEIMA will better enable Ameren Illinois to earn its allowed return on equity for its electric delivery service business. This framework is expected to give Ameren Illinois the earnings predictability to invest in modernizing its distribution system. However, the ICC's orders in 2012 for Ameren Illinois' initial and update filings jeopardize Ameren Illinois' ongoing ability to implement infrastructure improvements to the extent and on the timetable envisioned in the IEIMA. Ameren Illinois has appealed both of the ICC's 2012 electric rate orders to the courts and is also seeking a legislative solution to address the ICC's implementation of the IEIMA. Although Ameren Illinois intends to meet its IEIMA capital spending requirements, it is proceeding on a slower investment |
• | 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, even though the amount added to the monthly average yields of the 30-year United States treasury bonds will decrease to 580 basis points in 2013 from 590 basis points in 2012, due to expected increases in recoverable costs and rate base growth. |
• | Ameren Illinois' 2012 revenue requirement under the IEIMA framework was lower than the revenue requirement included in both the ICC's 2010 electric rate order and the ICC's September 2012 order related to Ameren Illinois' initial IEIMA filing. Consequently, Ameren recorded a $55 million regulatory liability to represent its estimate of the probable decrease in electric delivery service revenues expected to be approved by the ICC in December 2013 to provide Ameren Illinois recovery of all prudently and reasonably incurred costs and an allowed rate of return on common equity for 2012. Any decrease in electric delivery service revenues approved by the ICC in December 2013 will be refunded to customers during 2014 with interest pursuant to the provisions of the IEIMA. |
• | In January 2013, Ameren Illinois filed a request with the ICC to increase its annual revenues for natural gas delivery service by $50 million. 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 fuel costs above the net fuel 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-fuel 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 approximately $147 million over the next three years for energy efficiency programs. The order allows for Ameren Missouri to collect its |
• | As they continue to experience cost recovery pressures, 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. |
• | The MoPSC issued an order, in April 2011, with respect to its review of Ameren Missouri's FAC for the period from March 1, 2009, to September 30, 2009. The order required Ameren Missouri to refund $18 million, including $1 million for interest, to customers related to pretax earnings associated with certain long-term partial requirements sales made by Ameren Missouri after the loss of Noranda's load in a severe ice storm in January 2009. Ameren Missouri appealed this decision to the Cole County Circuit Court, which overturned the MoPSC's April 2011 order. The Cole County Circuit Court decision is being appealed by the MoPSC to the Missouri Court of Appeals. It is possible that the MoPSC could order additional refunds of approximately $25 million related to pretax earnings associated with these long-term partial requirements sales in periods after September 2009, and this could result in a charge to earnings in the period in which such an order is received. Separately, Ameren Missouri filed a request with the MoPSC in July 2011 for an accounting authority order that would allow Ameren Missouri to recover fixed costs totaling $36 million due to the loss of load caused by the severe 2009 ice storm in a future electric rate case. If the courts ultimately rule in favor of Ameren Missouri's position regarding the classification of the long-term partial requirements sales, Ameren Missouri would no longer seek to recover from customers the sum covered by the accounting authority order. |
• | Ameren and Ameren Missouri also 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's Callaway energy center's next scheduled refueling and maintenance outage will be in the spring of 2013. The expected duration of this outage is approximately 40 days. During a scheduled outage, which occurs every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC resulting in limited impact to earnings. |
• | 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 and global climate change, could result in significant increases in capital expenditures and operating costs. The compliance costs 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 intends to allocate its capital to those investment opportunities with the highest expected risk-adjusted returns. Ameren believes that because of its strategic location in the country, electric transmission may provide it with such an opportunity. MISO has approved three projects, which will 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 in service 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 current transmission expansion plan. These two projects are expected to be completed in 2018. The estimated 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, is being evaluated for inclusion in MISO's 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 |
• | For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, the FAC prudence review and related appeal, Taum Sauk matters, and separate FERC orders impacting Ameren Missouri and Ameren Illinois, see Note 2 - Rate and Regulatory Matters, Note 10 - Callaway Energy Center, and Note 15 - Commitments and Contingencies under Exhibit 99.4, Item 8, of this Current Report on Form 8-K. |
• | Ameren no longer considers the Merchant Generation segment to be a core component of its future business strategy. As a result, Ameren intends to exit its Merchant Generation segment before the end of the previously estimated useful lives of that segment's long-lived assets. In consideration of this determination, Ameren has begun planning to reduce, and ultimately to eliminate, the Merchant Generation segment's, including Genco's, reliance on Ameren's financial support and shared services support. |
• | On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations under Exhibit 99.4, Item 8, of this Current Report on Form 8-K 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 was subject to the receipt of approvals from FERC and approval of certain license transfers by the FCC. On October 11, 2013, Ameren received FERC approval for the divestiture of New AER to IPH. In August 2013, the FCC approved the license transfers. 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 discussed in more detail below. 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 |
• | Ameren expects a third-party sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers will be completed by the end of 2013. On October 11, 2013, Ameren received FERC approval for Genco's sale of the Elgin, Gibson City, and Grand Tower gas-fired energy centers to Medina Valley. |
• | 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. |
• | Ameren's divestiture of New AER and the Elgin, Gibson City, and Grand Tower energy centers may result in long-lived asset impairments, disposal-related losses, contingencies, reductions of existing deferred tax assets, and other consequences that are currently unknown. |
• | 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. |
• | 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 27.5 million megawatthours in 2013, with approximately 95% 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 realize by marketing power into the wholesale and retail markets. Ameren's Merchant Generation segment is adversely affected by the declining market price of power for any unhedged generation. Market prices for power have decreased over the past several years, especially sharply during the first quarter of 2012. |
• | As of December 31, 2012, Marketing Company had hedged approximately 25.5 million megawatthours of Merchant Generation's expected generation for 2013, at an average price of $36 per megawatthour. For 2014, Marketing Company had hedged approximately 14 million megawatthours of Merchant Generation's forecasted generation sales at an average price of $38 per megawatthour. For 2015, Marketing Company had hedged approximately 6.5 million megawatthours of Merchant Generation's forecasted generation sales at an average price of $40 per megawatthour. Any unhedged forecasted generation will be exposed to market prices at the time of |
• | To further reduce cash flow volatility, Merchant Generation seeks to hedge fuel costs consistent with power sales. As of December 31, 2012, for 2013 Merchant Generation had hedged fuel costs for approximately 25 million megawatthours of coal and up to 27 million megawatthours of base transportation at about $23 per megawatthour. For 2014, Merchant Generation had hedged fuel costs for approximately 13 million megawatthours of coal and up to 21 million megawatthours of base transportation at about $24 per megawatthour. For 2015, Merchant Generation had hedged fuel costs for approximately 6 million megawatthours of coal and up to 20 million megawatthours of base transportation at about $26 per megawatthour. |
• | In June 2012, FERC approved MISO's proposal to establish an annual capacity market within the RTO. MISO's inaugural annual capacity auction will be held in March 2013 for the June 2013 to May 2014 planning year. Participation in MISO's capacity auction is voluntary for load-serving entities as they will continue to be able to plan to meet all of their resource requirements outside of the auction, including through self-supply and/or bilateral contracts. |
• | The Merchant Generation segment continues to seek revenue growth opportunities. One such opportunity is Marketing Company's ability to sell additional electric capacity into PJM. Capacity market prices within PJM are higher than capacity market prices within MISO. In addition to the capacity related to Genco's Elgin energy center, which is located within PJM, Marketing Company expects to sell additional capacity associated with 681 megawatts of PJM-approved transmission capacity from MISO to PJM. This includes 84 megawatts of transmission capacity associated with AERG energy centers from October 2011 forward, and an additional 301 megawatts and 296 megawatts of transmission capacity associated with AERG and Genco energy centers, respectively, from June 2015 forward. Another revenue growth opportunity is Marketing Company's efforts to sell power to residential and small commercial customers in Illinois. Marketing Company is actively pursuing sales to customers choosing the state of Illinois municipal aggregation alternative for electric power supply. Marketing Company's sales to municipal aggregation customers at retail prices provide margins above the current wholesale market prices. Marketing Company will attempt to expand the volume of its sales to residential and small commercial customers through the municipal aggregation initiative. |
• | 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. 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 order also established a schedule of milestones for completion of |
• | 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 14 - Related Party Transactions with New AER under Exhibit 99.4, Item 8, of this Current Report on Form 8-K 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. |
• | As of December 31, 2012, Ameren had approximately $605 million in federal income tax net operating loss carryforwards (Ameren Missouri - $175 million and Ameren Illinois - $175 million) and $87 million in federal income tax credit carryforwards (Ameren Missouri - $11 million and Ameren Illinois - $- million). These carryforwards are expected to offset income tax liabilities for Ameren Missouri into 2014, and into 2015 for Ameren and Ameren Illinois, consistent with the tax allocation agreement. |
• | In December 2011, the IRS issued new guidance in the form of temporary regulations 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. This new 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. |
• | The American Taxpayer Relief Act of 2012, enacted into law on January 2, 2013, includes provisions accelerating the depreciation of certain property for income tax purposes. |
• | 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 Exhibit 99.4, Item 8, of this Current Report on Form 8-K 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. |
• | Ameren investments required to achieve compliance with known environmental laws and regulations relating to continuing operations from 2013 to 2022 are expected to be more than $1.1 billion. Ameren continues to closely monitor |
Accounting Estimate | Uncertainties Affecting Application |
• | Regulatory environment and external regulatory decisions and requirements |
• | Anticipated future regulatory decisions and their impact |
• | Impact of deregulation, rate freezes, prudency reviews, and opposition during the ratemaking process and ability to recover costs |
• | Ameren Illinois' assessment of and ability to estimate the current year’s electric delivery service costs to be reflected in revenues and recovered from customers in a subsequent year under the IEIMA performance-based formula ratemaking process. |
• | Our ability to identify derivatives |
• | Our ability to assess whether derivative contracts qualify for the NPNS exception |
• | Our ability to consume or produce notional values of derivative contracts |
• | Market conditions in the energy industry, especially the effects of price volatility and liquidity |
• | Valuation assumptions on longer-term contracts due to lack of observable inputs |
• | Effectiveness of derivatives that have been designated as hedges |
• | Counterparty default risk |
• | Changes in business, industry, laws, technology, or economic and market conditions |
• | Valuation assumptions and conclusions, including an appropriate discount rate and terminal year earnings multiple. |
• | Our assessment of market participants |
• | Estimated useful lives or duration of ownership of our significant long-lived assets |
• | Actions or assessments by our regulators |
• | Identification of an asset retirement obligation and assumptions about the timing of asset removals |
• | Future rate of return on pension and other plan assets |
• | Valuation inputs and assumptions used in the fair value measurements of plan assets excluding those inputs that are readily observable |
• | Interest rates used in valuing benefit obligations |
• | Health care cost trend rates |
• | Timing of employee retirements and mortality assumptions |
• | Ability to recover certain benefit plan costs from our ratepayers |
• | Changing market conditions that may affect investment and interest rate environments |
• | Impacts of the health care reform legislation enacted in 2010 |
• | Estimating financial impact of events |
• | Estimating likelihood of various potential outcomes |
• | Regulatory and political environments and requirements |
• | Outcome of legal proceedings, settlements or other factors |
• | Changes in regulation, expected scope of work, technology or timing of environmental remediation |
• | Changes in business, industry, laws, technology, or economic and market conditions affecting forecasted financial condition and/or results of operations |
• | Estimates of the amount and character of future taxable income |
• | Enacted tax rates applicable to taxable income in years in which temporary differences are recovered or settled |
• | Effectiveness of implementing tax planning strategies |
• | Changes in income tax laws |
• | Results of audits and examinations of filed tax returns by taxing authorities |
• | long-term and short-term variable-rate debt; |
• | fixed-rate debt; |
• | auction-rate long-term debt; and |
• | defined pension and postretirement benefit plans. |
2013 | 2014 | 2015 – 2017 | ||||||
Coal | 100 | % | 100 | % | 94 | % | ||
Coal transportation | 99 | 98 | 98 | |||||
Nuclear fuel | 100 | 99 | 49 | |||||
Natural gas for generation | 34 | 9 | 2 | |||||
Natural gas for distribution(a) | 82 | 34 | 9 | |||||
Purchased power for Ameren Illinois(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 January 2013 through March 2013. The year 2014 represents November 2013 through March 2014. This continues each successive year through March 2017. |
(b) | Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. |
2012 | |||
Fair value of contracts at beginning of year, net | $ | (89 | ) |
Contracts realized or otherwise settled during the period | 77 | ||
Changes in fair values attributable to changes in valuation technique and assumptions | — | ||
Fair value of new contracts entered into during the period | 16 | ||
Other changes in fair value | (205 | ) | |
Fair value of contracts outstanding at end of year, net | $ | (201 | ) |
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 | ||||||||||||||
Level 1 | $ | — | $ | (4 | ) | $ | — | $ | — | $ | (4 | ) | |||||||
Level 2(a) | (60 | ) | (39 | ) | (1 | ) | — | (100 | ) | ||||||||||
Level 3(b) | (8 | ) | (19 | ) | (20 | ) | (50 | ) | (97 | ) | |||||||||
Total | $ | (68 | ) | $ | (62 | ) | $ | (21 | ) | $ | (50 | ) | $ | (201 | ) |
(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 a Black-Scholes model that includes information from external sources and our estimates. Level 3 also includes option contract values based on our estimates. |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
AMEREN CORPORATION CONSOLIDATED STATEMENT OF INCOME (LOSS) (In millions, except per share amounts) | |||||||||||
Year Ended December 31, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Operating Revenues: | |||||||||||
Electric | $ | 4,857 | $ | 5,226 | $ | 5,153 | |||||
Gas | 924 | 1,001 | 1,116 | ||||||||
Total operating revenues | 5,781 | 6,227 | 6,269 | ||||||||
Operating Expenses: | |||||||||||
Fuel | 714 | 911 | 673 | ||||||||
Purchased power | 780 | 952 | 1,122 | ||||||||
Gas purchased for resale | 472 | 570 | 668 | ||||||||
Other operations and maintenance | 1,514 | 1,580 | 1,566 | ||||||||
Impairment and other charges | — | 123 | 64 | ||||||||
Depreciation and amortization | 667 | 646 | 627 | ||||||||
Taxes other than income taxes | 443 | 434 | 424 | ||||||||
Total operating expenses | 4,590 | 5,216 | 5,144 | ||||||||
Operating Income | 1,191 | 1,011 | 1,125 | ||||||||
Other Income and Expenses: | |||||||||||
Miscellaneous income | 70 | 68 | 88 | ||||||||
Miscellaneous expense | 37 | 23 | 32 | ||||||||
Total other income | 33 | 45 | 56 | ||||||||
Interest Charges | 391 | 387 | 415 | ||||||||
Income Before Income Taxes | 833 | 669 | 766 | ||||||||
Income Taxes | 309 | 245 | 274 | ||||||||
Income from Continuing Operations | 524 | 424 | 492 | ||||||||
Income (Loss) from Discontinued Operations, Net of Taxes (Note 16) | (1,498 | ) | 102 | (341 | ) | ||||||
Net Income (Loss) | (974 | ) | 526 | 151 | |||||||
Less: Net Income (Loss) Attributable to Noncontrolling Interests: | |||||||||||
Continuing Operations | 6 | 6 | 9 | ||||||||
Discontinued Operations | (6 | ) | 1 | 3 | |||||||
Net Income (Loss) Attributable to Ameren Corporation: | |||||||||||
Continuing Operations | 518 | 418 | 483 | ||||||||
Discontinued Operations | (1,492 | ) | 101 | (344 | ) | ||||||
Net Income (Loss) Attributable to Ameren Corporation | $ | (974 | ) | $ | 519 | $ | 139 | ||||
Earnings (Loss) per Common Share – Basic and Diluted: | |||||||||||
Continuing Operations | $ | 2.13 | $ | 1.73 | $ | 2.02 | |||||
Discontinued Operations | (6.14 | ) | 0.42 | (1.44 | ) | ||||||
Earnings (Loss) per Common Share – Basic and Diluted | $ | (4.01 | ) | $ | 2.15 | $ | 0.58 | ||||
Dividends per Common Share | $ | 1.600 | $ | 1.555 | $ | 1.540 | |||||
Average Common Shares Outstanding | 242.6 | 241.5 | 238.8 |
AMEREN CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) (In millions) | |||||||||||
Year Ended December 31, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Income from Continuing Operations | $ | 524 | $ | 424 | $ | 492 | |||||
Other Comprehensive Income (Loss), Net of Taxes | |||||||||||
Pension and other postretirement benefit plan activity, net of income taxes(benefit) of $(6), $(14), and $7, respectively | (8 | ) | (19 | ) | 10 | ||||||
Comprehensive Income from Continuing Operations | 516 | 405 | 502 | ||||||||
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 6 | 6 | 9 | ||||||||
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation | 510 | 399 | 493 | ||||||||
Income (Loss) from Discontinued Operations, Net of Income Taxes | (1,498 | ) | 102 | (341 | ) | ||||||
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes | 58 | (20 | ) | (16 | ) | ||||||
Comprehensive Income (Loss) from Discontinued Operations | (1,440 | ) | 82 | (357 | ) | ||||||
Less: Comprehensive Income (Loss) from Discontinuing Operations Attributable to Noncontrolling Interest | 2 | (5 | ) | 1 | |||||||
Comprehensive Income (Loss) from Discontinued Operations Attributable to Ameren Corporation | (1,442 | ) | 87 | (358 | ) | ||||||
Comprehensive Income (Loss) Attributable to Ameren Corporation | $ | (932 | ) | $ | 486 | $ | 135 |
AMEREN CORPORATION CONSOLIDATED BALANCE SHEET (In millions, except per share amounts) | |||||||
December 31, | |||||||
2012 | 2011 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 184 | $ | 248 | |||
Accounts receivable – trade (less allowance for doubtful accounts of $17 and $20, respectively) | 354 | 424 | |||||
Unbilled revenue | 291 | 285 | |||||
Miscellaneous accounts and notes receivable | 71 | 48 | |||||
Materials and supplies | 570 | 550 | |||||
Current regulatory assets | 247 | 215 | |||||
Current accumulated deferred income taxes, net | 170 | 98 | |||||
Other current assets | 98 | 151 | |||||
Assets of discontinued operations (Note 16) | 1,600 | 3,718 | |||||
Total current assets | 3,585 | 5,737 | |||||
Property and Plant, Net | 15,348 | 14,848 | |||||
Investments and Other Assets: | |||||||
Nuclear decommissioning trust fund | 408 | 357 | |||||
Goodwill | 411 | 411 | |||||
Intangible assets | 14 | 7 | |||||
Regulatory assets | 1,786 | 1,603 | |||||
Other assets | 667 | 760 | |||||
Total investments and other assets | 3,286 | 3,138 | |||||
TOTAL ASSETS | $ | 22,219 | $ | 23,723 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities: | |||||||
Current maturities of long-term debt | $ | 355 | $ | 179 | |||
Short-term debt | — | 148 | |||||
Accounts and wages payable | 533 | 592 | |||||
Taxes accrued | 50 | 53 | |||||
Interest accrued | 89 | 91 | |||||
Customer deposits | 107 | 98 | |||||
Mark-to-market derivative liabilities | 92 | 122 | |||||
Current regulatory liabilities | 100 | 133 | |||||
Other current liabilities | 168 | 195 | |||||
Liabilities of discontinued operations (Note 16) | 1,166 | 1,762 | |||||
Total current liabilities | 2,660 | 3,373 | |||||
Long-term Debt, Net | 5,802 | 5,853 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes, net | 3,176 | 2,810 | |||||
Accumulated deferred investment tax credits | 70 | 76 | |||||
Regulatory liabilities | 1,589 | 1,502 | |||||
Asset retirement obligations | 375 | 364 | |||||
Pension and other postretirement benefits | 1,138 | 1,253 | |||||
Other deferred credits and liabilities | 642 | 424 | |||||
Total deferred credits and other liabilities | 6,990 | 6,429 | |||||
Commitments and Contingencies (Notes 2, 10, 14, 15 and 16) | |||||||
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 | 5,616 | 5,598 | |||||
Retained earnings | 1,006 | 2,369 | |||||
Accumulated other comprehensive loss | (8 | ) | (50 | ) | |||
Total Ameren Corporation stockholders’ equity | 6,616 | 7,919 | |||||
Noncontrolling Interests | 151 | 149 | |||||
Total equity | 6,767 | 8,068 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 22,219 | $ | 23,723 |
AMEREN CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In millions) | |||||||||||
Year Ended December 31, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Cash Flows From Operating Activities: | |||||||||||
Net income (loss) | $ | (974 | ) | $ | 526 | $ | 151 | ||||
(Income) loss from discontinued operations, net of taxes | 1,498 | (102 | ) | 341 | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Impairment and other charges | — | 123 | 64 | ||||||||
Net gain on sales of properties | — | (3 | ) | (5 | ) | ||||||
Depreciation and amortization | 627 | 606 | 590 | ||||||||
Amortization of nuclear fuel | 83 | 61 | 54 | ||||||||
Amortization of debt issuance costs and premium/discounts | 20 | 16 | 16 | ||||||||
Deferred income taxes and investment tax credits, net | 260 | 253 | 384 | ||||||||
Allowance for equity funds used during construction | (36 | ) | (34 | ) | (52 | ) | |||||
Stock-based compensation costs | 29 | 17 | 15 | ||||||||
Other | (8 | ) | (14 | ) | 1 | ||||||
Changes in assets and liabilities: | |||||||||||
Receivables | 30 | 200 | (232 | ) | |||||||
Materials and supplies | (25 | ) | (27 | ) | 19 | ||||||
Accounts and wages payable | (34 | ) | (31 | ) | 23 | ||||||
Taxes accrued | (3 | ) | (5 | ) | 18 | ||||||
Assets, other | (6 | ) | 59 | (47 | ) | ||||||
Liabilities, other | 58 | (68 | ) | 88 | |||||||
Pension and other postretirement benefits | (23 | ) | (100 | ) | (9 | ) | |||||
Counterparty collateral, net | 41 | 36 | (70 | ) | |||||||
Premiums paid on long-term debt repurchases | (138 | ) | — | — | |||||||
Taum Sauk insurance recoveries, net of costs | — | (1 | ) | 54 | |||||||
Net cash provided by operating activities - continuing operations | 1,399 | 1,512 | 1,403 | ||||||||
Net cash provided by operating activities - discontinued operations | 291 | 366 | 420 | ||||||||
Net cash provided by operating activities | 1,690 | 1,878 | 1,823 | ||||||||
Cash Flows From Investing Activities: | |||||||||||
Capital expenditures | (1,063 | ) | (881 | ) | (941 | ) | |||||
Nuclear fuel expenditures | (91 | ) | (62 | ) | (68 | ) | |||||
Purchases of securities – nuclear decommissioning trust fund | (403 | ) | (220 | ) | (271 | ) | |||||
Sales and maturities of securities – nuclear decommissioning trust fund | 384 | 199 | 256 | ||||||||
Proceeds from sales of properties | — | 3 | 7 | ||||||||
Tax grants received related to renewable energy properties | 18 | — | — | ||||||||
Other | 2 | 12 | 2 | ||||||||
Net cash used in investing activities - continuing operations | (1,153 | ) | (949 | ) | (1,015 | ) | |||||
Net cash used in investing activities - discontinued operations | (157 | ) | (99 | ) | (81 | ) | |||||
Net cash used in investing activities | (1,310 | ) | (1,048 | ) | (1,096 | ) | |||||
Cash Flows From Financing Activities: | |||||||||||
Dividends on common stock | (382 | ) | (375 | ) | (368 | ) | |||||
Dividends paid to noncontrolling interest holders | (6 | ) | (6 | ) | (8 | ) | |||||
Short-term debt and credit facility repayments, net | (148 | ) | (481 | ) | (221 | ) | |||||
Redemptions, repurchases, and maturities: | |||||||||||
Long-term debt | (760 | ) | (155 | ) | (110 | ) | |||||
Preferred stock | — | — | (52 | ) | |||||||
Issuances: | |||||||||||
Long-term debt | 882 | — | — | ||||||||
Common stock | — | 65 | 80 | ||||||||
Capital issuance costs | (16 | ) | — | (9 | ) | ||||||
Advances received for construction | 4 | 5 | 29 | ||||||||
Repayments of advances received for construction | — | (73 | ) | (39 | ) | ||||||
Net cash used in financing activities - continuing operations | (426 | ) | (1,020 | ) | (698 | ) | |||||
Net cash used in financing activities - discontinued operations | — | (100 | ) | (106 | ) | ||||||
Net cash used in financing activities | (426 | ) | (1,120 | ) | (804 | ) | |||||
Net change in cash and cash equivalents | (46 | ) | (290 | ) | (77 | ) | |||||
Cash and cash equivalents at beginning of year | 255 | 545 | 622 | ||||||||
Cash and cash equivalents at end of year | $ | 209 | $ | 255 | $ | 545 | |||||
Less cash and cash equivalents of discontinued operations at end of year | 25 | 7 | 7 | ||||||||
Cash and cash equivalents of continuing operations at end of year | $ | 184 | $ | 248 | $ | 538 | |||||
Noncash financing activity – dividends on common stock | $ | (7 | ) | $ | — | $ | — | ||||
Cash Paid (Refunded) During the Year: | |||||||||||
Interest (net of $30, $30, and $34 capitalized, respectively) | $ | 433 | $ | 453 | $ | 494 | |||||
Income taxes, net | 1 | (61 | ) | (92 | ) |
AMEREN CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (In millions) | |||||||||||
December 31, | |||||||||||
2012 | 2011 | 2010 | |||||||||
Common Stock: | |||||||||||
Beginning of year | $ | 2 | $ | 2 | $ | 2 | |||||
Shares issued | — | — | — | ||||||||
Common stock, end of year | 2 | 2 | 2 | ||||||||
Other Paid-in Capital: | |||||||||||
Beginning of year | 5,598 | 5,520 | 5,412 | ||||||||
Shares issued | — | 65 | 80 | ||||||||
Stock-based compensation activity | 18 | 13 | 14 | ||||||||
Regulatory recovery of prior-period common stock issuance costs | — | — | 14 | ||||||||
Other paid-in capital, end of year | 5,616 | 5,598 | 5,520 | ||||||||
Retained Earnings: | |||||||||||
Beginning of year | 2,369 | 2,225 | 2,455 | ||||||||
Net income (loss) attributable to Ameren Corporation | (974 | ) | 519 | 139 | |||||||
Dividends | (389 | ) | (375 | ) | (368 | ) | |||||
Other | — | — | (1 | ) | |||||||
Retained earnings, end of year | 1,006 | 2,369 | 2,225 | ||||||||
Accumulated Other Comprehensive Loss: | |||||||||||
Derivative financial instruments, beginning of year | 7 | — | 10 | ||||||||
Change in derivative financial instruments | 18 | 7 | (10 | ) | |||||||
Derivative financial instruments, end of year | 25 | 7 | — | ||||||||
Deferred retirement benefit costs, beginning of year | (57 | ) | (17 | ) | (23 | ) | |||||
Change in deferred retirement benefit costs | 24 | (40 | ) | 6 | |||||||
Deferred retirement benefit costs, end of year | (33 | ) | (57 | ) | (17 | ) | |||||
Total accumulated other comprehensive loss, end of year | (8 | ) | (50 | ) | (17 | ) | |||||
Total Ameren Corporation Stockholders’ Equity | $ | 6,616 | $ | 7,919 | $ | 7,730 | |||||
Noncontrolling Interests: | |||||||||||
Beginning of year | 149 | 154 | 204 | ||||||||
Net income attributable to noncontrolling interest holders | — | 7 | 12 | ||||||||
Dividends paid to noncontrolling interest holders | (6 | ) | (6 | ) | (8 | ) | |||||
Redemptions of preferred stock | — | — | (52 | ) | |||||||
Other | 8 | (6 | ) | (2 | ) | ||||||
Noncontrolling interests, end of year | 151 | 149 | 154 | ||||||||
Total Equity | $ | 6,767 | $ | 8,068 | $ | 7,884 | |||||
Common stock shares at beginning of year | 242.6 | 240.4 | 237.4 | ||||||||
Shares issued | — | 2.2 | 3.0 | ||||||||
Common stock shares at end of year | 242.6 | 242.6 | 240.4 |
• | 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 Missouri was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and natural gas service to a 24,000-square-mile area in central and eastern Missouri. This area has an estimated population of 2.8 million and includes the Greater St. Louis area. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers. |
• | Ameren Illinois Company, or Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois was created by the merger of CILCO and IP with and into CIPS. CIPS was incorporated in Illinois in 1923 and is successor to a number of companies, the oldest of which was organized in 1902. Ameren Illinois supplies electric and natural gas utility service to portions of central and southern Illinois having an estimated population of 3.1 million in an area of 40,000 square miles. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 806,000 customers. |
• | AER consists of non-rate-regulated operations, including Genco, AERG, Marketing Company, and, through Genco, an 80% ownership interest in EEI, which Ameren consolidates for financial reporting purposes. On March 14, 2013, Ameren entered into a transaction agreement to divest New AER to IPH. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information regarding the divestiture. |
2012 | |||
Fuel(a) | $ | 198 | |
Gas stored underground | 131 | ||
Other materials and supplies | 241 | ||
$ | 570 | ||
2011 | |||
Fuel(a) | $ | 150 | |
Gas stored underground | 171 | ||
Other materials and supplies | 229 | ||
$ | 550 |
(a) | Consists of coal, oil, paint, propane, and tire chips. |
• | Macroeconomic conditions, including those conditions within Ameren Illinois’ service territory; |
• | Pending rate case outcomes and future rate case outcomes; |
• | Changes in laws and potential law changes; |
• | Observable industry market multiples; |
• | Achievement of IEIMA performance metrics and the yield of the 30-year United States treasury bonds; and |
• | Actual and forecasted financial performance. |
Ameren(a) | ||||
Balance at December 31, 2010 | $ | 403 | ||
Liabilities incurred | — | |||
Liabilities settled | (2 | ) | ||
Accretion in 2011(b) | 22 | |||
Change in estimates(c) | (54 | ) | ||
Balance at December 31, 2011 | $ | 369 | (d) | |
Liabilities incurred | — | |||
Liabilities settled | (6 | ) | ||
Accretion in 2012(b) | 20 | |||
Change in estimates(e) | (8 | ) | ||
Balance at December 31, 2012 | $ | 375 |
(a) | The nuclear decommissioning trust fund assets of 408 million and 357 million as of December 31, 2012, and 2011, respectively, were restricted for decommissioning of the Callaway energy center. |
(b) | Accretion expense was recorded as an increase to regulatory assets. |
(c) | Ameren changed its fair value estimate related to its Callaway energy center decommissioning costs because of a cost study performed in 2011 and a decline in the cost escalation factor assumptions. Additionally, Ameren changed the fair value estimates related to retirement costs for asbestos removal, river structures and CCR storage facilities. |
(d) | Balance included $5 million in "Other current liabilities" on the consolidated balance sheet as of December 31, 2011. |
(e) | Ameren changed the fair value estimates for asbestos removal. The estimates for asbestos removal costs at Hutsonville and Meredosia energy centers decreased because less asbestos than anticipated was found in the energy centers' structures during reviews made after the closure of these energy centers, and because removal was more cost efficient than anticipated due to the closure. |
2012 | 2011 | ||||||||
Current regulatory assets: | |||||||||
Under-recovered FAC(a)(b) | $ | 145 | $ | 83 | |||||
Under-recovered Illinois electric power costs(a)(c) | — | 4 | |||||||
Under-recovered PGA(a)(c) | 12 | 8 | |||||||
MTM derivative losses(d) | 90 | 120 | |||||||
Total current regulatory assets | $ | 247 | $ | 215 | |||||
Noncurrent regulatory assets: | |||||||||
Pension and postretirement benefit costs(e) | $ | 772 | $ | 878 | |||||
Income taxes(f) | 235 | 239 | |||||||
Asset retirement obligations(g) | 5 | 6 | |||||||
Callaway costs(a)(h) | 44 | 48 | |||||||
Unamortized loss on reacquired debt(a)(i) | 181 | 47 | |||||||
Recoverable costs - contaminated facilities(j) | 248 | 102 | |||||||
MTM derivative losses(d) | 135 | 100 | |||||||
SO2 emission allowances sale tracker(k) | 2 | 6 | |||||||
Storm costs(l) | 9 | 16 | |||||||
Demand-side costs(a)(m) | 73 | 70 | |||||||
Reserve for workers’ compensation liabilities(n) | 12 | 13 | |||||||
Credit facilities fees(o) | 6 | 10 | |||||||
Employee separation costs(p) | 2 | 6 | |||||||
Common stock issuance costs(q) | 7 | 10 | |||||||
Construction accounting for pollution control equipment(a)(r) | 23 | 25 | |||||||
Other(s) | 32 | 27 | |||||||
Total noncurrent regulatory assets | $ | 1,786 | $ | 1,603 | |||||
Current regulatory liabilities: | |||||||||
Over-recovered FAC(t) | $ | — | $ | 12 | |||||
Over-recovered Illinois electric power costs(c) | 58 | 64 | |||||||
Over-recovered PGA(c) | 15 | 9 | |||||||
MTM derivative gains(u) | 19 | 46 | |||||||
Wholesale distribution refund(v) | 8 | 2 | |||||||
Total current regulatory liabilities | $ | 100 | $ | 133 | |||||
Noncurrent regulatory liabilities: | |||||||||
Income taxes(w) | $ | 46 | $ | 48 | |||||
Removal costs(x) | 1,347 | 1,269 | |||||||
Asset retirement obligation(g) | 80 | 29 | |||||||
MTM derivative gains(u) | 2 | 82 | |||||||
Bad debt rider(y) | 12 | 10 | |||||||
Pension and postretirement benefit costs tracker(z) | 23 | 38 | |||||||
Energy efficiency rider(aa) | 20 | 24 | |||||||
IEIMA revenue requirement reconciliation(ab) | 55 | — | |||||||
Other(ac) | 4 | 2 | |||||||
Total noncurrent regulatory liabilities | $ | 1,589 | $ | 1,502 |
(a) | These assets earn a return. |
(b) | Under-recovered fuel costs for periods from June 2010 through December 2012. Specific accumulation periods aggregate the under-recovered costs over four months, any related adjustments that occur over the following four months, and the recovery from customers that occurs over the next eight months. |
(c) | Costs under- or over-recovered from utility customers. Amounts will be recovered from, or refunded to, customers within one year of the deferral. |
(d) | Deferral of commodity-related derivative MTM losses. The December 31, 2011 balance included the MTM losses on financial contracts entered into by Ameren Illinois with Marketing Company, which expired in December 2012. |
(e) | These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets), and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. See Note 11 - Retirement Benefits for additional information. |
(f) | Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 - Income Taxes for amortization period. |
(g) | Recoverable or refundable removal costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 - Summary of Significant Accounting Policies - Asset Retirement Obligations. |
(h) | Ameren Missouri’s Callaway energy center operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the energy center's current operating license which expires in 2024. |
(i) | Losses related to reacquired debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued. |
(j) | The recoverable portion of accrued environmental site liabilities, primarily collected from electric and natural gas customers through ICC-approved cost recovery riders. The period of recovery will depend on the timing of actual expenditures. See Note 15 - Commitments and Contingencies for additional information. |
(k) | A regulatory tracking mechanism for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2 discounts received under such contracts, as approved in a MoPSC order. The MoPSC’s May 2010 electric rate order discontinued any future deferrals under this tracking mechanism. The MoPSC’s December 2012 rate order approved the amortization of these costs through December 2014. |
(l) | Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. As approved by the December 2012 MoPSC electric rate order, the 2006, 2007, and 2008 storm costs are being amortized through December 2014. As approved by the May 2010 MoPSC electric rate order, the 2009 storm costs are being amortized through June 2015. |
(m) | Demand-side costs, including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. Costs incurred from May 2008 through September 2008 are being amortized over a 10-year period that began in March 2009. Costs incurred from October 2008 through December 2009 are being amortized over a six-year period that began in July 2010. Costs incurred from January 2010 through February 2011 are being amortized over a six-year period that began in August 2011. Costs incurred from March 2011 through July 2012 are being amortized over a six-year period that began in January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case. |
(n) | Reserve for workers’ compensation claims. The period of recovery will depend on the timing of actual expenditures. |
(o) | Ameren Missouri’s costs incurred to enter into and maintain the 2012 Ameren Missouri Credit Agreement. These costs are being amortized over five years, beginning in November 2012. These costs are being amortized to construction work in progress, which will be subsequently depreciated when assets are placed into service. |
(p) | Costs incurred for voluntary and involuntary separation programs. The 2009 Ameren Missouri-related costs are being amortized over two years, beginning in January 2013, as approved by the December 2012 MoPSC electric rate order. The 2009 Ameren Illinois-related costs are being amortized over three years, beginning in May 2010, as approved by the April 2010 ICC electric and natural gas rate order. |
(q) | The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to recover its portion of Ameren’s September 2009 common stock issuance costs. These costs are being amortized over five years, beginning in July 2010. |
(r) | The MoPSC’s May 2010 electric rate order allowed Ameren Missouri to record an allowance for funds used during construction for pollution control equipment at its Sioux energy center until the cost of that equipment was placed in customer rates. The amortization of these costs will be over the expected life of the Sioux energy center. |
(s) | The Ameren Illinois total includes Ameren Illinois Merger integration and optimization costs, which are amortized over four years, beginning in January 2012. The Ameren Illinois total includes costs related to delivery service rate cases. The 2012 natural gas rate case costs are being amortized over a two-year period that began in January 2012. The electric rate case costs for the IEIMA initial rate filing are being amortized over a three-year period that began in January 2012. The Ameren Illinois total also includes a portion of the unamortized debt fair value adjustment recorded upon Ameren's acquisition of IP. This portion is being amortized over the remaining life of the related debt, beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007. At Ameren Missouri, the balance primarily includes cost associated with the retirement of renewable energy credits and solar rebates to fulfill its renewable energy portfolio requirement. Costs incurred from January 2010 through July 2012 are being amortized over three years, beginning January 2013. The amortization period for the costs incurred after July 2012 will be determined in a future Ameren Missouri electric rate case. |
(t) | Over-recovered fuel costs from March 2009 through September 2009 as ordered by the MoPSC in April 2011. Customer refunds concluded in 2012. Specific accumulation periods aggregate the over-recovered costs over four months, any related adjustments occur over the following four months, and then recovery from customers occurs over the next eight months. |
(u) | Deferral of commodity-related derivative MTM gains. |
(v) | Estimated refund to wholesale electric customers. See 2011 Wholesale Distribution Rate Case above. |
(w) | Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 - Income Taxes for amortization period. |
(x) | Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations. |
(y) | A regulatory tracking mechanism for the difference between the level of bad debt expense incurred by Ameren Illinois under GAAP and the level of such costs included in electric and natural gas rates. The over-recovery relating to 2010 was refunded to customers from June 2011 through May 2012. The over-recovery relating to 2011 is being refunded to customers from June 2012 through May 2013. The over-recovery relating to 2012 will be refunded to customers from June 2013 through May 2014. |
(z) | A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by Ameren Missouri under GAAP and the level of such costs built into rates. For periods prior to August 2012, the MoPSC's December 2012 electric rate order directed the amortization to occur over five years, beginning in January 2013. For periods after August 2012, the amortization period will be determined in a future Ameren Missouri electric rate case. |
(aa) | A regulatory tracking mechanism that allows Ameren Illinois to recover its electric and natural gas costs associated with developing, implementing, and evaluating customer energy efficiency and demand response programs. This over-recovery will be refunded to customers over the following 12 months after the plan year. |
(ab) | The difference between Ameren Illinois' 2012 revenue requirement calculated under the IEIMA's performance-based formula ratemaking framework, and the revenue requirement included in customer rates for 2012. Subject to ICC approval, this liability will be refunded to customers in 2014. |
(ac) | Balance primarily includes an Ameren Missouri liability relating to its 2010 property tax refund. The MoPSC's December 2012 electric rate order directed a refund to customers over a two-year period, beginning in January 2013. |
Ameren(a) | |||
2012 | |||
Property and plant, at original cost: | |||
Electric | $ | 20,942 | |
Natural gas | 1,854 | ||
22,796 | |||
Less: Accumulated depreciation and amortization | 8,346 | ||
14,450 | |||
Construction work in progress: | |||
Nuclear fuel in process | 317 | ||
Other | 581 | ||
Property and plant, net | $ | 15,348 | |
2011 | |||
Property and plant, at original cost: | |||
Electric | $ | 20,098 | |
Natural gas | 1,751 | ||
21,849 | |||
Less: Accumulated depreciation and amortization | 7,868 | ||
13,981 | |||
Construction work in progress: | |||
Nuclear fuel in process | 255 | ||
Other | 612 | ||
Property and plant, net | $ | 14,848 |
(a) | Amounts include two electric generation CTs under two separate capital lease agreements. The gross asset value of those agreements was $228 million and $229 million at December 31, 2012, and 2011, respectively. The total accumulated depreciation associated with the two CTs was $52 million and $52 million at December 31, 2012, and 2011, respectively. In addition, Ameren has investments in debt securities, which are classified as held-to-maturity, related to the two CTs from the city of Bowling Green and Audrain County. As of December 31, 2012, and 2011, the carrying value of these debt securities was $304 million and $309 million, respectively. |
2012 | $ | 103 | |
2011 | 92 | ||
2010 | 70 |
2012 Missouri Credit Agreement | 2012 Illinois Credit Agreement | |||||
Ameren | $ | 500 | $ | 300 | ||
Ameren Missouri | 800 | (a) | ||||
Ameren Illinois | (a) | $ | 800 |
(a) | Not applicable. |
2010 Missouri Credit Agreement ($800 million) (Terminated) | Ameren (Parent) | Ameren Missouri | Total | ||||||||
2012 | |||||||||||
Average daily borrowings outstanding during 2012(a) | $ | — | $ | 1 | $ | 1 | |||||
Outstanding credit facility borrowings at period end | — | — | — | ||||||||
Weighted-average interest rate during 2012(a) | — | % | 4.15 | % | 4.15 | % | |||||
Peak credit facility borrowings during 2012(a) | $ | — | $ | 50 | $ | 50 | |||||
Peak interest rate during 2012 | — | % | 4.15 | % | 4.15 | % | |||||
2011 | |||||||||||
Average daily borrowings outstanding during 2011 | $ | 105 | $ | — | $ | 105 | |||||
Outstanding credit facility borrowings at period end | — | — | — | ||||||||
Weighted-average interest rate during 2011 | 2.30 | % | — | 2.30 | % | ||||||
Peak credit facility borrowings during 2011 | $ | 340 | $ | — | $ | 340 | |||||
Peak interest rate during 2011 | 4.30 | % | — | 4.30 | % |
(a) | Calculated through termination date. |
2012 | 2011 | ||||||
Ameren (Parent): | |||||||
8.875% Senior unsecured notes due 2014 | $ | 425 | $ | 425 | |||
Less: Unamortized discount and premium | (1 | ) | (1 | ) | |||
Long-term debt, net | $ | 424 | $ | 424 | |||
Ameren Missouri: | |||||||
Senior secured notes:(a) | |||||||
5.25% Senior secured notes due 2012 | $ | — | $ | 173 | |||
4.65% Senior secured notes due 2013 | 200 | 200 | |||||
5.50% Senior secured notes due 2014 | 104 | 104 | |||||
4.75% Senior secured notes due 2015 | 114 | 114 | |||||
5.40% Senior secured notes due 2016 | 260 | 260 | |||||
6.40% Senior secured notes due 2017 | 425 | 425 | |||||
6.00% Senior secured notes due 2018(b) | 179 | 250 | |||||
5.10% Senior secured notes due 2018 | 199 | 200 | |||||
6.70% Senior secured notes due 2019(b) | 329 | 450 | |||||
5.10% Senior secured notes due 2019 | 244 | 300 | |||||
5.00% Senior secured notes due 2020 | 85 | 85 | |||||
5.50% Senior secured notes due 2034 | 184 | 184 | |||||
5.30% Senior secured notes due 2037 | 300 | 300 | |||||
8.45% Senior secured notes due 2039(b) | 350 | 350 | |||||
3.90% Senior secured notes due 2042(b) | 485 | — | |||||
Environmental improvement and pollution control revenue bonds: | |||||||
1992 Series due 2022(c)(d) | 47 | 47 | |||||
1993 5.45% Series due 2028(e) | 44 | 44 | |||||
1998 Series A due 2033(c)(d) | 60 | 60 | |||||
1998 Series B due 2033(c)(d) | 50 | 50 | |||||
1998 Series C due 2033(c)(d) | 50 | 50 | |||||
Capital lease obligations: | |||||||
City of Bowling Green capital lease (Peno Creek CT) through 2022 | 64 | 69 | |||||
Audrain County capital lease (Audrain County CT) due 2023 | 240 | 240 | |||||
Total long-term debt, gross | 4,013 | 3,955 | |||||
Less: Unamortized discount and premium | (7 | ) | (5 | ) | |||
Less: Maturities due within one year | (205 | ) | (178 | ) | |||
Long-term debt, net | $ | 3,801 | $ | 3,772 |
2012 | 2011 | ||||||
Ameren Illinois: | |||||||
Senior secured notes: | |||||||
8.875% Senior secured notes due 2013(f)(h) | $ | 150 | $ | 150 | |||
6.20% Senior secured notes due 2016(f) | 54 | 54 | |||||
6.25% Senior secured notes due 2016(g) | 75 | 75 | |||||
6.125% Senior secured notes due 2017(g)(i) | 250 | 250 | |||||
6.25% Senior secured notes due 2018(g)(i) | 144 | 337 | |||||
9.75% Senior secured notes due 2018(g)(i) | 313 | 400 | |||||
2.70% Senior secured notes due 2022(g)(i) | 400 | — | |||||
6.125% Senior secured notes due 2028(g) | 60 | 60 | |||||
6.70% Senior secured notes due 2036(g) | 61 | 61 | |||||
6.70% Senior secured notes due 2036(f) | 42 | 42 | |||||
Environmental improvement and pollution control revenue bonds: | |||||||
6.20% Series 1992B due 2012 | — | 1 | |||||
2000 Series A 5.50% due 2014 | — | 51 | |||||
5.90% Series 1993 due 2023(j) | 32 | 32 | |||||
5.70% 1994A Series due 2024(k) | 36 | 36 | |||||
1993 Series C-1 5.95% due 2026(l) | 35 | 35 | |||||
1993 Series C-2 5.70% due 2026(l) | 8 | 8 | |||||
1993 Series B-1 due 2028(d)(l) | 17 | 17 | |||||
5.40% 1998A Series due 2028(k) | 19 | 19 | |||||
5.40% 1998B Series due 2028(k) | 33 | 33 | |||||
Fair-market value adjustments | 4 | 5 | |||||
Total long-term debt, gross | 1,733 | 1,666 | |||||
Less: Unamortized discount and premium | (6 | ) | (8 | ) | |||
Less: Maturities due within one year | (150 | ) | (1 | ) | |||
Long-term debt, net | $ | 1,577 | $ | 1,657 | |||
Ameren consolidated long-term debt, net | $ | 5,802 | $ | 5,853 |
(a) | These notes are collaterally secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any first mortgage bonds issued under the Ameren Missouri mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Missouri first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2042. |
(b) | Ameren Missouri has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its first mortgage bonds. Ameren Missouri has also agreed to prevent a first mortgage bond release date from occurring as long as any of the 8.45% senior secured notes due 2039 and any of the 3.90% senior secured notes due 2042 remain outstanding. |
(c) | These bonds are secured by first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage indenture and have a fall-away lien provision similar to that of Ameren Missouri's senior secured notes. The bonds are also backed by an insurance guarantee policy. |
(d) | Interest rates, and periods during which such rates apply, vary depending on our selection of defined rate modes. Maximum interest rates could range up to 18% depending on the series of bonds. The average interest rates for 2012 and 2011 were as follows: |
2012 | 2011 | ||||
Ameren Missouri 1992 Series | 0.30 | % | 0.34 | % | |
Ameren Missouri 1998 Series A | 0.65 | % | 0.69 | % | |
Ameren Missouri 1998 Series B | 0.64 | % | 0.68 | % | |
Ameren Missouri 1998 Series C | 0.64 | % | 0.69 | % | |
Ameren Illinois 1993 Series B-1 | 0.22 | % | 0.28 | % |
(e) | These bonds are first mortgage bonds issued by Ameren Missouri under the Ameren Missouri mortgage bond indenture and are secured by substantially all Ameren Missouri property and franchises. The bonds are callable at 100% of par value. |
(f) | These notes are collaterally secured by first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the CILCO mortgage indenture remain outstanding. Redemption, purchase, or maturity of all first mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the first mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the CILCO first mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the first mortgage bond lien protection associated with these notes to fall away until 2023. |
(g) | These notes are collaterally secured by mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture. The notes have a fall-away lien provision and will remain secured only as long as any series of first mortgage bonds issued under the Ameren Illinois mortgage indenture remain outstanding. Redemption, purchase, or maturity of all mortgage bonds, including first mortgage bonds currently outstanding and any that may be issued in the future, would result in a release of the mortgage bonds currently securing these notes, at which time these notes would become unsecured obligations. Based on the Ameren Illinois mortgage bonds and senior secured notes currently outstanding, and assuming no early retirement of any series of such securities in full, we do not expect the mortgage bond lien protection associated with these notes to fall away until 2028. |
(h) | Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its CILCO first mortgage bonds, and therefore a CILCO first mortgage bond release date will not occur while any of such notes are outstanding. |
(i) | Ameren Illinois has agreed, during the life of these notes, not to optionally redeem, purchase or otherwise retire in full its Ameren Illinois mortgage bonds, and therefore an Ameren Illinois first mortgage bond release date will not occur as long as any of these notes are outstanding. |
(j) | These bonds are first mortgage bonds issued by Ameren Illinois under the CILCO mortgage indenture and are secured by substantially all property of the former CILCO. The bonds are callable at 100% of par value. |
(k) | These bonds are mortgage bonds issued by Ameren Illinois under the Ameren Illinois mortgage indenture and are secured by substantially all property of the former IP and CIPS. The bonds are callable at 100% of par value. The bonds are also backed by an insurance guarantee policy. |
(l) | The bonds are callable at 100% of par value. |
Ameren (Parent)(a) | Ameren Missouri(a) | Ameren Illinois(a)(b) | Ameren Consolidated | ||||||||||||
2013 | $ | — | $ | 205 | $ | 150 | $ | 355 | |||||||
2014 | 425 | 109 | — | 534 | |||||||||||
2015 | — | 120 | — | 120 | |||||||||||
2016 | — | 266 | 129 | 395 | |||||||||||
2017 | — | 431 | 250 | 681 | |||||||||||
Thereafter | — | 2,882 | 1,200 | 4,082 | |||||||||||
Total | $ | 425 | $ | 4,013 | $ | 1,729 | $ | 6,167 |
(a) | Excludes unamortized discount and premium of $1 million, $7 million, and $6 million at Ameren (Parent), Ameren Missouri, and Ameren Illinois, respectively. |
(b) | Excludes $4 million related to Ameren Illinois’ long-term debt fair-market value adjustments, which are being amortized to interest expense over the remaining life of the debt. |
Redemption Price(per share) | 2012 | 2011 | |||||||||||
Ameren Missouri: | |||||||||||||
Without par value and stated value of $100 per share, 25 million shares authorized | |||||||||||||
$3.50 Series | 130,000 shares | $ | 110.00 | $ | 13 | $ | 13 | ||||||
$3.70 Series | 40,000 shares | 104.75 | 4 | 4 | |||||||||
$4.00 Series | 150,000 shares | 105.625 | 15 | 15 | |||||||||
$4.30 Series | 40,000 shares | 105.00 | 4 | 4 | |||||||||
$4.50 Series | 213,595 shares | 110.00 | (a) | 21 | 21 | ||||||||
$4.56 Series | 200,000 shares | 102.47 | 20 | 20 | |||||||||
$4.75 Series | 20,000 shares | 102.176 | 2 | 2 | |||||||||
$5.50 Series A | 14,000 shares | 110.00 | 1 | 1 | |||||||||
Total | $ | 80 | $ | 80 | |||||||||
Ameren Illinois: | |||||||||||||
With par value of $100 per share, 2 million shares authorized | |||||||||||||
4.00% Series | 144,275 shares | $ | 101.00 | $ | 14 | $ | 14 | ||||||
4.08% Series | 45,224 shares | 103.00 | 5 | 5 | |||||||||
4.20% Series | 23,655 shares | 104.00 | 2 | 2 | |||||||||
4.25% Series | 50,000 shares | 102.00 | 5 | 5 | |||||||||
4.26% Series | 16,621 shares | 103.00 | 2 | 2 | |||||||||
4.42% Series | 16,190 shares | 103.00 | 2 | 2 | |||||||||
4.70% Series | 18,429 shares | 103.00 | 2 | 2 | |||||||||
4.90% Series | 73,825 shares | 102.00 | 7 | 7 | |||||||||
4.92% Series | 49,289 shares | 103.50 | 5 | 5 | |||||||||
5.16% Series | 50,000 shares | 102.00 | 5 | 5 | |||||||||
6.625% Series | 124,273.75 shares | 100.00 | 12 | 12 | |||||||||
7.75% Series | 4,542 shares | 100.00 | 1 | 1 | |||||||||
Total | $ | 62 | $ | 62 | |||||||||
Total Ameren(b) | $ | 142 | $ | 142 |
(a) | In the event of voluntary liquidation, $105.50. |
(b) | Preferred stock not subject to mandatory redemption of Ameren's subsidiaries was included in "Noncontrolling Interests" on Ameren's consolidated balance sheet. |
Senior Secured Notes | Principal Amount Repurchased | Premium Plus Accrued and Unpaid Interest(a) | Principal Amount Outstanding After Tender Offer | ||||||||
6.00% senior secured notes due 2018 | $ | 71 | $ | 19 | $ | 179 | |||||
6.70% senior secured notes due 2019 | 121 | 35 | 329 | ||||||||
5.10% senior secured notes due 2018 | 1 | (b) | 199 | ||||||||
5.10% senior secured notes due 2019 | 56 | 12 | 244 |
(a) | The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $485 million 3.90% senior secured notes due 2042. |
(b) | Amount is less than $1 million. |
Senior Secured Notes | Principal Amount Repurchased | Premium Plus Accrued and Unpaid Interest(a) | Principal Amount Outstanding After Tender Offer | ||||||||
9.75% senior secured notes due 2018 | $ | 87 | $ | 36 | $ | 313 | |||||
6.25% senior secured notes due 2018 | 194 | 47 | 144 |
(a) | The premiums paid in association with the tender offer were recorded as a regulatory asset and are being amortized over the life of the $400 million 2.70% senior secured notes due 2022. |
Required Interest Coverage Ratio(a) | Actual Interest Coverage Ratio | Bonds Issuable(b) | Required Dividend Coverage Ratio(c) | Actual Dividend Coverage Ratio | Preferred Stock Issuable | ||||||||
Ameren Missouri | >2.0 | 4.6 | $ | 4,056 | >2.5 | 122.8 | $ | 2,351 | |||||
Ameren Illinois | >2.0 | 7.1 | 3,439 | (d) | >1.5 | 2.8 | 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. |
2012 | 2011 | 2010 | |||||||||
Ameren: | |||||||||||
Miscellaneous income: | |||||||||||
Interest and dividend income | $ | 4 | (a) | $ | 3 | $ | 4 | ||||
Interest income on industrial development revenue bonds | 28 | 28 | 28 | ||||||||
Allowance for equity funds used during construction | 36 | 34 | 52 | ||||||||
Other | 2 | 3 | 4 | ||||||||
Total miscellaneous income | $ | 70 | $ | 68 | $ | 88 | |||||
Miscellaneous expense: | |||||||||||
Donations | $ | 24 | (b) | $ | 8 | $ | 19 | ||||
Other | 13 | 15 | 13 | ||||||||
Total miscellaneous expense | $ | 37 | $ | 23 | $ | 32 |
(a) | Includes interest income relating to a 2012 refund of charges included in an expired power purchase agreement with Entergy. See Note 2 - Rate and Regulatory Matters for additional information. |
(b) | Includes Ameren Illinois' one-time $7.5 million donation and $1 million annual donation to the Illinois Science and Energy Innovation Trust and $1 million annual donation for customer assistance programs pursuant to the IEIMA as a result of Ameren Illinois' 2012 participation 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) | ||||||||||||||
2012 | 2011 | 2012 | 2011 | 2012 | 2011 | ||||||||||||
Coal (in tons) | 96 | 116 | (d) | (d) | (d) | (d) | |||||||||||
Fuel oils (in gallons)(e) | (d) | (d) | (d) | (d) | 70 | 53 | |||||||||||
Natural gas (in mmbtu) | 20 | 50 | — | 9 | 147 | 193 | |||||||||||
Power (in megawatthours) | 24 | 12 | 2 | 1 | 23 | 21 | |||||||||||
Renewable energy credits(f) | 15 | 16 | (d) | (d) | (d) | (d) | |||||||||||
Uranium (pounds in thousands) | 5,142 | 5,553 | (d) | (d) | 446 | 148 |
(a) | Accrual contracts include commodity contracts that do not qualify as derivatives. As of December 31, 2012, 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 December 31, 2012, these contracts ran through December 2014 for power. |
(c) | As of December 31, 2012, these contracts ran through October 2015, March 2017, May 2032, and September 2014 for fuel oils, natural gas, power, and uranium, respectively. |
(d) | Not applicable. |
(e) | Fuel oils consist of heating and crude oil. |
(f) | A renewable energy credit is created for every megawatthour of renewable energy generated. Ameren contracts include renewable energy credits from solar and wind-generated power. |
Balance Sheet Location | 2012 | 2011 | |||||||
Derivative assets not designated as hedging instruments(a) | |||||||||
Commodity contracts: | |||||||||
Fuel oils | Other current assets | $ | 8 | $ | 17 | ||||
Other assets | 4 | 6 | |||||||
Natural gas | Other current assets | 1 | 3 | ||||||
Other assets | 1 | 1 | |||||||
Power | Other current assets | 14 | 30 | ||||||
Other assets | 1 | 77 | |||||||
Total assets | $ | 29 | $ | 134 | |||||
Derivative liabilities not designated as hedging instruments(a) | |||||||||
Commodity contracts: | |||||||||
Fuel oils | MTM derivative liabilities | $ | 2 | $ | 1 | ||||
Other deferred credits and liabilities | 2 | — | |||||||
Natural gas | MTM derivative liabilities | 64 | 103 | ||||||
Other deferred credits and liabilities | 45 | 92 | |||||||
Power | MTM derivative liabilities | 25 | 18 | ||||||
Other deferred credits and liabilities | 90 | 8 | |||||||
Uranium | MTM derivative liabilities | 1 | — | ||||||
Other deferred credits and liabilities | 1 | 1 | |||||||
Total liabilities | $ | 230 | $ | 223 |
(a) | Includes derivatives subject to regulatory deferral. |
2012 | 2011 | |||||||
Cumulative gains (losses) deferred in regulatory liabilities or assets: | ||||||||
Fuel oils derivative contracts(a) | $ | 4 | $ | 19 | ||||
Natural gas derivative contracts(b) | (107 | ) | (191 | ) | ||||
Power derivative contracts(c) | (99 | ) | 81 | |||||
Uranium derivative contracts(d) | (2 | ) | (1 | ) |
(a) | Represents net gains on fuel oils derivative contracts. These contracts are a partial hedge of transportation costs for coal through October 2015 as of December 31, 2012. Current gains deferred as regulatory liabilities include $4 million as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012. |
(b) | Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through March 2017 as of December 31, 2012. Current gains deferred as regulatory liabilities include $1 million as of December 31, 2012. Current losses deferred as regulatory assets include $64 million as of December 31, 2012. |
(c) | Represents net losses associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 as of December 31, 2012. Current gains deferred as regulatory liabilities include $14 million as of December 31, 2012. Current losses deferred as regulatory assets include $24 million as of December 31, 2012. |
(d) | Represents net losses on uranium derivative contracts. These contracts are a partial hedge of uranium requirements through September 2014 as of December 31, 2012. Current losses deferred as regulatory assets include $1 million as of December 31, 2012, respectively. |
Affiliates | Coal Producers | Commodity Marketing Companies | Electric Utilities | Financial Companies | Municipalities/ Cooperatives | Total | |||||||||||||||||||||
2012 | $ | — | $ | — | $ | 2 | $ | 3 | $ | 15 | $ | 3 | $ | 23 | |||||||||||||
2011 | $ | 1 | $ | 35 | $ | 85 | $ | 4 | $ | 27 | $ | 4 | $ | 156 |
Affiliates | Coal Producers | Commodity Marketing Companies | Electric Utilities | Financial Companies | Municipalities/ Cooperatives | Total | |||||||||||||||||||||
2012 | $ | — | $ | — | $ | 1 | $ | 1 | $ | 10 | $ | 3 | $ | 15 | |||||||||||||
2011 | $ | 1 | $ | 35 | $ | 85 | $ | 3 | $ | 22 | $ | 4 | $ | 150 |
Aggregate Fair Value of Derivative Liabilities(a) | Cash Collateral Posted | Potential Aggregate Amount of Additional Collateral Required(b) | |||||||||
2012 | $ | 226 | $ | 61 | $ | 155 | |||||
2011 | $ | 322 | $ | 104 | $ | 211 |
(a) | Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures. |
(b) | As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements. |
Location of Gain (Loss) Recognized in Income | Gain (Loss) Recognized in Income | |||||||||
2012 | 2011 | |||||||||
Natural gas (generation) | Operating Expenses - Fuel | $ | — | $ | (1 | ) |
Gain (Loss) Recognized In Regulatory Liabilities or Regulatory Assets | ||||||||
2012 | 2011 | |||||||
Fuel oils | $ | (15 | ) | $ | — | |||
Natural gas | 84 | (26 | ) | |||||
Power | (180 | ) | 80 | |||||
Uranium | (1 | ) | (3 | ) | ||||
Total | $ | (112 | ) | $ | 51 |
Fair Value | Range [Weighted | ||||||||
Assets | Liabilities | Valuation Technique(s) | Unobservable Input | Average] | |||||
Level 3 Derivative asset and liability - commodity contracts(a): | |||||||||
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 | ||||||||
Option model | Volatilities(%)(b) | 7 - 27 [24] | |||||||
Power(e) | 14 | (114 | ) | Discounted cash flow | Average bid/ask consensus peak and off-peak 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($/credit)(b) | 5 - 7 [6] | |||||||
Uranium | — | (2 | ) | Discounted cash flow | Average bid/ask consensus pricing($/pound)(b) | 43 - 46 [44] |
(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 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. |
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: | 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 | $ | 269 | $ | 144 | $ | 22 | $ | 435 | |||||||||
Liabilities: | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Fuel oils | 1 | — | 3 | 4 | |||||||||||||
Natural gas | 7 | 102 | — | 109 | |||||||||||||
Power | — | 1 | 114 | 115 | |||||||||||||
Uranium | — | — | 2 | 2 | |||||||||||||
Total | $ | 8 | $ | 103 | $ | 119 | $ | 230 |
(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: | Derivative assets - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | 20 | $ | — | $ | 3 | $ | 23 | |||||||||
Natural gas | 2 | — | 2 | 4 | |||||||||||||
Power | — | 1 | 106 | 107 | |||||||||||||
Total derivative assets - commodity contracts | $ | 22 | $ | 1 | $ | 111 | $ | 134 | |||||||||
Nuclear decommissioning trust fund(b): | |||||||||||||||||
Cash and cash equivalents | 3 | — | — | 3 | |||||||||||||
Equity securities: | |||||||||||||||||
U.S. large capitalization | 234 | — | — | 234 | |||||||||||||
Debt securities: | |||||||||||||||||
Corporate bonds | — | 44 | — | 44 | |||||||||||||
Municipal bonds | — | 1 | — | 1 | |||||||||||||
U.S. treasury and agency securities | — | 65 | — | 65 | |||||||||||||
Asset-backed securities | — | 10 | — | 10 | |||||||||||||
Other | — | 1 | — | 1 | |||||||||||||
Total nuclear decommissioning trust fund | $ | 237 | $ | 121 | $ | — | $ | 358 | |||||||||
Total | $ | 259 | $ | 122 | $ | 111 | $ | 492 | |||||||||
Liabilities: | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | 1 | $ | — | $ | — | $ | 1 | |||||||||
Natural gas | 19 | — | 176 | 195 | |||||||||||||
Power | — | 1 | 25 | 26 | |||||||||||||
Uranium | — | — | 1 | 1 | |||||||||||||
Total | $ | 20 | $ | 1 | $ | 202 | $ | 223 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Balance excludes $(1) million of receivables, payables, and accrued income, net. |
Net Derivative Commodity Contracts | ||||||||
2012 | 2011 | |||||||
Fuel oils: | ||||||||
Beginning balance at January 1 | $ | 3 | $ | 30 | ||||
Realized and unrealized gains (losses): | ||||||||
Included in regulatory assets/liabilities | (1 | ) | 19 | |||||
Total realized and unrealized gains (losses) | (1 | ) | 19 | |||||
Purchases | 7 | 4 | ||||||
Sales | (3 | ) | (1 | ) | ||||
Settlements | (2 | ) | (30 | ) | ||||
Transfers into Level 3 | 1 | — | ||||||
Transfers out of Level 3 | — | (19 | ) | |||||
Ending balance at December 31 | $ | 5 | $ | 3 | ||||
Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | (1 | ) | $ | (11 | ) | ||
Natural gas: | ||||||||
Beginning balance at January 1 | $ | (174 | ) | $ | (148 | ) | ||
Realized and unrealized gains (losses): | ||||||||
Included in regulatory assets/liabilities | (27 | ) | (115 | ) | ||||
Total realized and unrealized gains (losses) | (27 | ) | (115 | ) | ||||
Purchases | — | 1 | ||||||
Sales | — | (1 | ) | |||||
Settlements | 16 | 89 | ||||||
Transfers out of Level 3 | 185 | — | ||||||
Ending balance at December 31 | $ | — | $ | (174 | ) | |||
Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | — | $ | (78 | ) | |||
Power: | ||||||||
Beginning balance at January 1 | $ | 81 | $ | 19 | ||||
Realized and unrealized gains (losses): | ||||||||
Included in regulatory assets/liabilities | (175 | ) | 55 | |||||
Total realized and unrealized gains (losses) | (175 | ) | 55 | |||||
Purchases | 21 | 30 | ||||||
Sales | (1 | ) | (1 | ) | ||||
Settlements | (22 | ) | (22 | ) | ||||
Transfers into Level 3 | — | (1 | ) | |||||
Transfers out of Level 3 | (4 | ) | 1 | |||||
Ending balance at December 31 | $ | (100 | ) | $ | 81 | |||
Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | (175 | ) | (a) | $ | (25 | ) | |
Uranium: | ||||||||
Beginning balance at January 1 | $ | (1 | ) | $ | 2 | |||
Realized and unrealized gains (losses): | ||||||||
Included in regulatory assets/liabilities | (2 | ) | (3 | ) | ||||
Total realized and unrealized gains (losses) | (2 | ) | (3 | ) | ||||
Purchases | — | (1 | ) | |||||
Settlements | 1 | 1 | ||||||
Ending balance at December 31 | $ | (2 | ) | $ | (1 | ) | ||
Change in unrealized gains (losses) related to assets/liabilities held at December 31 | $ | (1 | ) | $ | — |
(a) | The change in unrealized losses was due to decreases in long-term power prices applied to 20-year Ameren Illinois swap contracts, which expire in May 2032. |
2012 | 2011 | ||||||
Derivative commodity contracts: | |||||||
Transfers into Level 3 / Transfers out of Level 1 - Fuel oils | $ | 1 | $ | — | |||
Transfers out of Level 3 / Transfers into Level 1 - Fuel oils | — | (19 | ) | ||||
Transfers out of Level 3 / Transfers into Level 2 - Natural gas | 185 | — | |||||
Transfers into Level 3 / Transfers out of Level 2 - Power | — | (1 | ) | ||||
Transfers out of Level 3 / Transfers into Level 2 - Power | (4 | ) | 1 | ||||
Net fair value of Level 3 transfers | $ | 182 | $ | (19 | ) |
2012 | 2011 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Long-term debt and capital lease obligations (including current portion) | $ | 6,157 | $ | 7,110 | $ | 6,032 | $ | 6,961 | |||||||
Preferred stock(a) | 142 | 123 | 142 | 92 |
(a) | Preferred stock along with the noncontrolling interest of EEI is recorded in "Noncontrolling Interests" on the consolidated balance sheet. |
2012 | 2011 | 2010 | |||||||||
Proceeds from sales and maturities | $ | 384 | $ | 199 | $ | 256 | |||||
Gross realized gains | 6 | 5 | 5 | ||||||||
Gross realized losses | 2 | 4 | 4 |
Security Type | Cost | Gross Unrealized Gain | Gross Unrealized Loss | Fair Value | |||||||||||
2012 | |||||||||||||||
Debt securities | $ | 133 | $ | 8 | (a) | $ | 141 | ||||||||
Equity securities | 145 | 130 | 11 | 264 | |||||||||||
Cash | 1 | — | — | 1 | |||||||||||
Other(b) | 2 | — | — | 2 | |||||||||||
Total | $ | 281 | $ | 138 | $ | 11 | $ | 408 | |||||||
2011 | |||||||||||||||
Debt securities | $ | 114 | $ | 7 | (a) | $ | 121 | ||||||||
Equity securities | 145 | 101 | 12 | 234 | |||||||||||
Cash | 3 | — | — | 3 | |||||||||||
Other(b) | (1 | ) | — | — | (1 | ) | |||||||||
Total | $ | 261 | $ | 108 | $ | 12 | $ | 357 |
(a) | Amount less than $1 million. |
(b) | Represents payables relating to pending security purchases, net of receivables related to pending security sales and interest receivables. |
Cost | Fair Value | ||||||
Less than 5 years | $ | 78 | $ | 79 | |||
5 years to 10 years | 32 | 35 | |||||
Due after 10 years | 23 | 27 | |||||
Total | $ | 133 | $ | 141 |
Less than 12 Months | 12 Months or Greater | Total | |||||||||||||||||||||
Fair Value | Gross Unrealized Losses | Fair Value | Gross Unrealized Losses | Fair Value | Gross Unrealized Losses | ||||||||||||||||||
Debt securities | $ | 17 | $ (a) | $ (a) | $ (a) | $ | 17 | $ (a) | |||||||||||||||
Equity securities | 7 | 1 | 14 | 10 | 21 | 11 | |||||||||||||||||
Total | $ | 24 | $ | 1 | $ | 14 | $ | 10 | $ | 38 | $ | 11 |
(a) | Amount less than $1 million. |
2012 | 2011 | ||||||||||||||
Pension Benefits | Postretirement Benefits | Pension Benefits | Postretirement Benefits | ||||||||||||
Accumulated benefit obligation at end of year | $ | 3,829 | (a) | $ | 3,553 | (a) | |||||||||
Change in benefit obligation: | |||||||||||||||
Net benefit obligation at beginning of year | $ | 3,764 | $ | 1,145 | $ | 3,366 | $ | 1,036 | |||||||
Service cost | 81 | 22 | 73 | 20 | |||||||||||
Interest cost | 166 | 47 | 175 | 54 | |||||||||||
Plan amendments(b) | — | — | (16 | ) | — | ||||||||||
Participant contributions | — | 16 | — | 18 | |||||||||||
Actuarial (gain) loss | 240 | (10 | ) | 335 | 71 | ||||||||||
Benefits paid | (200 | ) | (69 | ) | (169 | ) | (63 | ) | |||||||
Early retiree reinsurance program receipt | (a) | 2 | (a) | 3 | |||||||||||
Federal subsidy on benefits paid | (a) | 4 | (a) | 6 | |||||||||||
Net benefit obligation at end of year | 4,051 | 1,157 | 3,764 | 1,145 | |||||||||||
Change in plan assets: | |||||||||||||||
Fair value of plan assets at beginning of year | 2,814 | 836 | 2,664 | 735 | |||||||||||
Actual return on plan assets | 385 | 104 | 223 | 8 | |||||||||||
Employer contributions | 128 | 45 | 96 | 129 | |||||||||||
Federal subsidy on benefits paid | (a) | 4 | (a) | 6 | |||||||||||
Early retiree reinsurance program receipt | (a) | 2 | (a) | 3 | |||||||||||
Participant contributions | — | 16 | — | 18 | |||||||||||
Benefits paid | (200 | ) | (69 | ) | (169 | ) | (63 | ) | |||||||
Fair value of plan assets at end of year | 3,127 | 938 | 2,814 | 836 | |||||||||||
Funded status - deficiency | 924 | 219 | 950 | 309 | |||||||||||
Accrued benefit cost at December 31 | $ | 924 | $ | 219 | $ | 950 | $ | 309 | |||||||
Amounts recognized in the consolidated balance sheet consist of: | |||||||||||||||
Current liability | $ | 3 | $ | 2 | $ | 3 | $ | 3 | |||||||
Noncurrent liability | 921 | 217 | 947 | 306 | |||||||||||
Net liability recognized | $ | 924 | $ | 219 | $ | 950 | $ | 309 | |||||||
Amounts recognized in regulatory assets consist of: | |||||||||||||||
Net actuarial loss | $ | 699 | $ | 103 | $ | 734 | $ | 177 | |||||||
Prior service cost (credit) | (6 | ) | (24 | ) | (7 | ) | (28 | ) | |||||||
Transition obligation | — | — | — | 2 | |||||||||||
Amounts (pretax) recognized in accumulated OCI consist of: | |||||||||||||||
Net actuarial loss | 65 | 5 | 54 | 5 | |||||||||||
Prior service cost (credit) | (14 | ) | (6 | ) | (16 | ) | (7 | ) | |||||||
Total | $ | 744 | $ | 78 | $ | 765 | $ | 149 |
(a) | Not applicable. |
(b) | In 2011, Ameren’s pension plan was amended to adjust the calculation of the future benefit obligation of approximately 430 labor union-represented employees from a traditional, final pay formula to a cash balance formula. |
Pension Benefits | Postretirement Benefits | ||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||
Discount rate at measurement date | 4.00 | % | 4.50 | % | 4.00 | % | 4.50 | % | |||
Increase in future compensation | 3.50 | 3.50 | 3.50 | 3.50 | |||||||
Medical cost trend rate (initial) | — | — | 5.00 | 5.50 | |||||||
Medical cost trend rate (ultimate) | — | — | 5.00 | 5.00 | |||||||
Years to ultimate rate | 0 | 0 | 0 | 1 year |
Pension Benefits | Postretirement Benefits | ||||||||||||||||||||||
2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||||||||||||||
$ | 128 | $ | 96 | $ | 81 | $ | 45 | $ | 129 | $ | 36 |
Asset Category | Target Allocation 2013 | Percentage of Plan Assets at December 31, | |||||
2012 | 2011 | ||||||
Pension Plan: | |||||||
Cash and cash equivalents | 0 - 5 % | 2 | % | 2 | % | ||
Equity securities: | |||||||
U.S. large capitalization | 29 - 39 | 34 | 33 | % | |||
U.S. small and mid-capitalization | 2 - 12 | 7 | 7 | % | |||
International and emerging markets | 9 - 19 | 13 | 11 | % | |||
Total equity | 50 - 60 | 54 | 51 | % | |||
Debt securities | 35 - 45 | 39 | 42 | % | |||
Real estate | 0 - 9 | 4 | 4 | % | |||
Private equity | 0 - 4 | 1 | 1 | % | |||
Total | 100 | % | 100 | % | |||
Postretirement Plans: | |||||||
Cash and cash equivalents | 0 - 10 % | 4 | % | 4 | % | ||
Equity securities: | |||||||
U.S. large capitalization | 33 - 43 | 40 | % | 38 | % | ||
U.S. small and mid-capitalization | 3 - 13 | 8 | % | 8 | % | ||
International | 10 - 20 | 14 | % | 13 | % | ||
Total equity | 55 - 65 | 62 | % | 59 | % | ||
Debt securities | 30 - 40 | 34 | % | 37 | % | ||
Total | 100 | % | 100 | % |
Quoted Prices in Active Markets for Identified Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||
Cash and cash equivalents | $ | 1 | $ | 28 | $ | — | $ | 29 | |||||||
Equity securities: | |||||||||||||||
U.S. large capitalization | 83 | 1,007 | — | 1,090 | |||||||||||
U.S. small and mid-capitalization | 235 | — | — | 235 | |||||||||||
International and emerging markets | 134 | 301 | — | 435 | |||||||||||
Debt securities: | |||||||||||||||
Corporate bonds | — | 832 | — | 832 | |||||||||||
Municipal bonds | — | 176 | — | 176 | |||||||||||
U.S. treasury and agency securities | — | 250 | — | 250 | |||||||||||
Other | — | 17 | — | 17 | |||||||||||
Real estate | — | — | 118 | 118 | |||||||||||
Private equity | — | — | 19 | 19 | |||||||||||
Derivative assets | — | — | — | — | |||||||||||
Derivative liabilities | (1 | ) | — | — | (1 | ) | |||||||||
Total | $ | 452 | $ | 2,611 | $ | 137 | $ | 3,200 | |||||||
Less: Medical benefit assets at December 31(a) | (102 | ) | |||||||||||||
Plus: Net receivables at December 31(b) | 29 | ||||||||||||||
Fair value of pension plans assets at year end | $ | 3,127 |
(a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation. |
(b) | Receivables related to pending security sales, offset by payables related to pending security purchases. |
Quoted Prices in Active Markets for Identified Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||
Cash and cash equivalents | $ | — | $ | 30 | $ | — | $ | 30 | |||||||
Equity securities: | |||||||||||||||
U.S. large capitalization | 72 | 901 | — | 973 | |||||||||||
U.S. small and mid-capitalization | 202 | — | — | 202 | |||||||||||
International and emerging markets | 115 | 208 | — | 323 | |||||||||||
Debt securities: | |||||||||||||||
Corporate bonds | — | 794 | — | 794 | |||||||||||
Municipal bonds | — | 176 | — | 176 | |||||||||||
U.S. treasury and agency securities | — | 230 | — | 230 | |||||||||||
Other | — | 23 | — | 23 | |||||||||||
Real estate | — | — | 108 | 108 | |||||||||||
Private equity | — | — | 23 | 23 | |||||||||||
Derivative assets | 1 | — | — | 1 | |||||||||||
Derivative liabilities | (1 | ) | — | — | (1 | ) | |||||||||
Total | $ | 389 | $ | 2,362 | $ | 131 | $ | 2,882 | |||||||
Less: Medical benefit assets at December 31(a) | (91 | ) | |||||||||||||
Plus: Net receivables at December 31(b) | 23 | ||||||||||||||
Fair value of pension plans assets at year end | $ | 2,814 |
(a) | Medical benefit (health and welfare) component for accounts maintained in accordance with Section 401(h) of the Internal Revenue Code (401(h) accounts) to fund a portion of the postretirement obligation. |
(b) | Receivables related to pending security sales, offset by payables related to pending security purchases. |
Beginning Balance at January 1, | Actual Return on Plan Assets Related to Assets Still Held at the Reporting Date | Actual Return on Plan Assets Related to Assets Sold During the Period | Purchases, Sales, and Settlements, net | Net Transfers into (out of) of Level 3 | Ending Balance at December 31, | ||||||||||||||||||
2012: | |||||||||||||||||||||||
Real estate | $ | 108 | $ | 7 | $ | — | $ | 3 | $ | — | $ | 118 | |||||||||||
Private equity | 23 | (7 | ) | 8 | (5 | ) | — | 19 | |||||||||||||||
2011: | |||||||||||||||||||||||
Real estate | $ | 98 | $ | 10 | $ | — | $ | — | $ | — | $ | 108 | |||||||||||
Private equity | 28 | (10 | ) | 11 | (6 | ) | — | 23 |
Quoted Prices in Active Markets for Identified Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||
Cash and cash equivalents | $ | 83 | $ | — | $ | — | $ | 83 | |||||||
Equity securities: | |||||||||||||||
U.S. large capitalization | 245 | 88 | — | 333 | |||||||||||
U.S. small and mid-capitalization | 66 | — | — | 66 | |||||||||||
International | 45 | 69 | — | 114 | |||||||||||
Debt securities: | |||||||||||||||
Corporate bonds | — | 88 | — | 88 | |||||||||||
Municipal bonds | — | 91 | — | 91 | |||||||||||
U.S. treasury and agency securities | — | 67 | — | 67 | |||||||||||
Asset-backed securities | — | 18 | — | 18 | |||||||||||
Other | — | 22 | — | 22 | |||||||||||
Total | $ | 439 | $ | 443 | $ | — | $ | 882 | |||||||
Plus: Medical benefit assets at December 31(a) | 102 | ||||||||||||||
Less: Net payables at December 31(b) | (46 | ) | |||||||||||||
Fair value of postretirement benefit plans assets at year end | $ | 938 |
(a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
(b) | Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales. |
Quoted Prices in Active Markets for Identified Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||
Cash and cash equivalents | $ | 1 | $ | 65 | $ | — | $ | 66 | |||||||
Equity securities: | |||||||||||||||
U.S. large capitalization | 206 | 78 | — | 284 | |||||||||||
U.S. small and mid-capitalization | 57 | — | — | 57 | |||||||||||
International | 38 | 56 | — | 94 | |||||||||||
Debt securities: | |||||||||||||||
Corporate bonds | — | 71 | — | 71 | |||||||||||
Municipal bonds | — | 80 | — | 80 | |||||||||||
U.S. treasury and agency securities | — | 69 | — | 69 | |||||||||||
Asset-backed securities | — | 23 | — | 23 | |||||||||||
Other | — | 34 | — | 34 | |||||||||||
Total | $ | 302 | $ | 476 | $ | — | $ | 778 | |||||||
Plus: Medical benefit assets at December 31(a) | 91 | ||||||||||||||
Less: Net payables at December 31(b) | (33 | ) | |||||||||||||
Fair value of postretirement benefit plans assets at year end | $ | 836 |
(a) | Medical benefit (health and welfare) component for 401(h) accounts to fund a portion of the postretirement obligation. These 401(h) assets are included in the pension plan assets shown above. |
(b) | Payables related to pending security purchases, offset by Medicare, interest receivables, and receivables related to pending security sales. |
Pension Benefits | Postretirement Benefits | ||||||
2012 | |||||||
Service cost | $ | 81 | $ | 22 | |||
Interest cost | 166 | 47 | |||||
Expected return on plan assets | (208 | ) | (56 | ) | |||
Amortization of: | |||||||
Transition obligation | — | 2 | |||||
Prior service cost | (3 | ) | (6 | ) | |||
Actuarial loss | 75 | 5 | |||||
Net periodic benefit cost | $ | 111 | $ | 14 | |||
2011 | |||||||
Service cost | $ | 73 | $ | 20 | |||
Interest cost | 175 | 54 | |||||
Expected return on plan assets | (211 | ) | (50 | ) | |||
Amortization of: | |||||||
Transition obligation | — | 2 | |||||
Prior service cost | (1 | ) | (6 | ) | |||
Actuarial loss | 41 | 3 | |||||
Net periodic benefit cost | $ | 77 | $ | 23 | |||
2010 | |||||||
Service cost | $ | 65 | $ | 18 | |||
Interest cost | 181 | 58 | |||||
Expected return on plan assets | (208 | ) | (51 | ) | |||
Amortization of: | |||||||
Transition obligation | — | 2 | |||||
Prior service cost | 6 | (6 | ) | ||||
Actuarial loss | 18 | — | |||||
Net periodic benefit cost | $ | 62 | $ | 21 |
Pension Benefits | Postretirement Benefits | ||||||
Ameren | Ameren | ||||||
Regulatory assets: | |||||||
Prior service cost (credit) | $ | (1 | ) | $ | (4 | ) | |
Net actuarial loss | 97 | 19 | |||||
Accumulated OCI: | |||||||
Prior service cost (credit) | (2 | ) | (1 | ) | |||
Net actuarial loss | 5 | — | |||||
Total | $ | 99 | $ | 14 |
Pension Benefits | Postretirement Benefits | ||||||||||||||||||
Paid from Qualified Trust | Paid from Company Funds | Paid from Qualified Trust | Paid from Company Funds | Federal Subsidy | |||||||||||||||
2013 | $ | 229 | $ | 3 | $ | 58 | $ | 2 | $ | 3 | |||||||||
2014 | 236 | 3 | 60 | 2 | 3 | ||||||||||||||
2015 | 239 | 3 | 62 | 2 | 4 | ||||||||||||||
2016 | 245 | 3 | 65 | 2 | 4 | ||||||||||||||
2017 | 248 | 3 | 68 | 2 | 4 | ||||||||||||||
2018 - 2022 | 1,279 | 13 | 384 | 11 | 19 |
Pension Benefits | Postretirement Benefits | ||||||||||||||||
2012 | 2011 | 2010 | 2012 | 2011 | 2010 | ||||||||||||
Discount rate at measurement date | 4.50 | % | 5.25 | % | 5.75 | % | 4.50 | % | 5.25 | % | 5.75 | % | |||||
Expected return on plan assets | 7.75 | 8.00 | 8.00 | 7.50 | 7.75 | 8.00 | |||||||||||
Increase in future compensation | 3.50 | 3.50 | 3.50 | 3.50 | 3.50 | 3.50 | |||||||||||
Medical cost trend rate (initial) | — | — | — | 5.50 | 6.00 | 6.50 | |||||||||||
Medical cost trend rate (ultimate) | — | — | — | 5.00 | 5.00 | 5.00 | |||||||||||
Years to ultimate rate | 0 | 0 | 0 | 1 year | 2 years | 3 years |
Pension Benefits | Postretirement Benefits | ||||||||||||||
Service Cost and Interest Cost | Projected Benefit Obligation | Service Cost and Interest Cost | Postretirement Benefit Obligation | ||||||||||||
0.25% decrease in discount rate | $ | (2 | ) | $ | 121 | $ | — | $ | 34 | ||||||
0.25% increase in salary scale | 2 | 13 | — | — | |||||||||||
1.00% increase in annual medical trend | — | — | — | 36 | |||||||||||
1.00% decrease in annual medical trend | — | — | (1 | ) | (34 | ) |
Performance Share Units | ||||||
Share Units | Weighted-average Fair Value per Unit | |||||
Nonvested at January 1, 2012 | 1,156,831 | $ | 31.70 | |||
Granted(a) | 717,151 | 35.68 | ||||
Unearned or forfeited(b) | (477,928 | ) | 32.04 | |||
Earned and vested(c) | (203,567 | ) | 34.01 | |||
Nonvested at December 31, 2012 | 1,192,487 | $ | 33.56 |
(a) | Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in January 2012 under the 2006 Plan. |
(b) | Includes share units granted in 2010 that were not earned based on performance provisions of the award grants. |
(c) | Includes share units granted in 2010 that vested as of December 31, 2012, that were earned pursuant to the provisions of the award grants. Also includes share units that vested due to 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. |
2012 | 2011 | 2010 | ||||
Statutory federal income tax rate: | 35 | % | 35 | % | 35 | % |
Increases (decreases) from: | ||||||
Depreciation differences | (1 | ) | (1 | ) | (3 | ) |
Amortization of investment tax credit | (1 | ) | (1 | ) | (1 | ) |
State tax | 5 | 4 | 5 | |||
Reserve for uncertain tax positions | — | 1 | (1 | ) | ||
Tax credits | — | (1 | ) | (1 | ) | |
Change in federal tax law(a) | — | — | 2 | |||
Other permanent items(b) | (1 | ) | — | — | ||
Effective income tax rate | 37 | % | 37 | % | 36 | % |
(a) | Relates to change in taxation of prescription drug benefits to retiree participants from the enactment in 2010 of the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010. |
(b) | Permanent items are treated differently for book and tax purposes and primarily include nondeductible expense related to lobbying and stock issuance expenses. |
2012 | 2011 | 2010 | |||||||
Current taxes: | |||||||||
Federal | $ | 40 | $ | (6 | ) | $ | 3 | ||
State | 9 | (2 | ) | (1 | ) | ||||
Deferred taxes: | |||||||||
Federal | 205 | 206 | 247 | ||||||
State | 61 | 53 | 32 | ||||||
Deferred investment tax credits, amortization | (6 | ) | (6 | ) | (7 | ) | |||
Total income tax expense | $ | 309 | $ | 245 | $ | 274 |
2012 | 2011 | |||||
Accumulated deferred income taxes, net liability (asset): | ||||||
Plant related | $ | 3,512 | $ | 3,162 | ||
Deferred intercompany tax gain/basis step-up | 39 | 54 | ||||
Regulatory assets, net | 73 | 73 | ||||
Deferred employee benefit costs | (323 | ) | (320 | ) | ||
Purchase accounting | (27 | ) | (28 | ) | ||
ARO | (17 | ) | (12 | ) | ||
Other(a) | (251 | ) | (217 | ) | ||
Total net accumulated deferred income tax liabilities | $ | 3,006 | $ | 2,712 |
(a) | Includes deferred tax assets related to net operating loss and tax credit carryforwards detailed in the table below. |
2012 | |||
Net operating loss carryforwards: | |||
Federal(a) | $ | 173 | |
State(b) | 27 | ||
Total net operating loss carryforwards | $ | 200 | |
Tax credit carryforwards: | |||
Federal(c) | $ | 86 | |
State(d) | 25 | ||
State valuation allowance(e) | (2 | ) | |
Total tax credit carryforwards | $ | 109 |
(a) | These will begin to expire in 2028. |
(b) | These will begin to expire in 2017. |
(c) | These will begin to expire in 2029. |
(d) | These will begin to expire in 2013. |
(e) | This balance increased by $1 million during 2012. |
2012 | 2011 | 2010 | |||||||
Unrecognized tax benefits - beginning of year | $ | 148 | $ | 246 | $ | 135 | |||
Increases based on tax positions prior to current year | 5 | 22 | 72 | ||||||
Decreases based on tax positions prior to current year | (13 | ) | (125 | ) | (38 | ) | |||
Increases based on tax positions related to current year | 17 | 17 | 77 | ||||||
Changes related to settlements with taxing authorities | — | (10 | ) | — | |||||
Decreases related to the lapse of statute of limitations | (1 | ) | (2 | ) | — | ||||
Unrecognized tax benefits - end of year | $ | 156 | $ | 148 | $ | 246 | |||
Total unrecognized tax benefits that, if recognized, would affect the effective tax rates | $ | 1 | $ | 1 | $ | — |
2012 | 2011 | 2010 | |||||||
Liability for interest - beginning of year | $ | 5 | $ | 17 | $ | 8 | |||
Interest charges (income) | 1 | (11 | ) | 9 | |||||
Interest payment | — | (1 | ) | — | |||||
Liability for interest - end of year | $ | 6 | $ | 5 | $ | 17 |
• | $189 million related to Ameren's Merchant Generation segment, primarily for Marketing Company as support for physically and financially settled power transactions with its counterparties. The amounts above do not represent incremental consolidated Ameren obligations; rather, they represent Ameren parental guarantees of subsidiary obligations to third parties 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 $25 million at December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices. |
• | $100 million associated with the guarantee agreement between Ameren and AERG entered into on March 28, 2012, relating to the put option agreement between Genco and AERG. On March 14, 2013, Genco exercised its option under the amended put option agreement with Medina |
• | $50 million guarantee to MISO for all of Ameren's subsidiaries who are MISO market participants. Ameren's estimated exposure for obligations under transactions covered by this guarantee was $32 million at December 31, 2012, which represents the total amount Ameren (parent) could be required to fund based on December 31, 2012 market prices. |
• | $15 million related to requirements for asset transactions, leasing, and other service agreements. At December 31, 2012, Ameren estimated it had no exposure to any of these guarantees. |
Agreement | Income Statement Line Item | Amount | |||||
Ameren Missouri and Genco gas | Operating Revenues | 2012 | $ | 1 | |||
transportation agreement | 2011 | 1 | |||||
2010 | 1 | ||||||
Ameren Illinois and ATXI transmission services agreement | Operating Revenues | 2012 | 16 | ||||
with Marketing Company | 2011 | 11 | |||||
2010 | 10 | ||||||
Total Operating Revenues | 2012 | $ | 17 | ||||
2011 | 12 | ||||||
2010 | 11 | ||||||
Ameren Illinois power supply agreements | Purchased Power | 2012 | $ | 311 | |||
with Marketing Company | 2011 | 232 | |||||
2010 | 233 | ||||||
Ameren Illinois gas purchases from Genco | Gas Purchased for Resale | 2012 | $ | — | |||
2011 | — | ||||||
2010 | 1 |
Type and Source of Coverage | Maximum Coverages | Maximum Assessments | ||||||
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) | ||
Energy Risk Assurance Company | $ | 64 | (g) | $ | — |
(a) | Provided through mandatory participation in an industrywide retrospective premium assessment program. |
(b) | Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed U.S. commercial reactor, payable at $17.5 million per year. |
(c) | Limit of liability for each incident under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $118 million per incident for each licensed reactor it operates with a maximum of $17.5 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors. |
(d) | Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage. |
(e) | 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 the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. |
(g) | Provides the replacement power cost insurance in the event of a prolonged accidental outage at our nuclear energy center. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 - Related Party Transactions with New AER for more information on this affiliate transaction. |
Total | 2013 | 2014 | 2015 | 2016 | 2017 | After 5 Years | |||||||||||||||||||||
Capital lease payments(a) | $ | 588 | $ | 32 | $ | 32 | $ | 33 | $ | 33 | $ | 33 | $ | 425 | |||||||||||||
Less amount representing interest | 284 | 27 | 27 | 27 | 27 | 27 | 149 | ||||||||||||||||||||
Present value of minimum capital lease payments | $ | 304 | $ | 5 | $ | 5 | $ | 6 | $ | 6 | $ | 6 | $ | 276 | |||||||||||||
Operating leases(b) | 138 | 19 | 14 | 14 | 14 | 14 | 63 | ||||||||||||||||||||
Total lease obligations | $ | 442 | $ | 24 | $ | 19 | $ | 20 | $ | 20 | $ | 20 | $ | 339 |
(a) | See Properties under Part I, Item 2, and Note 3 - Property and Plant, Net of this report for additional information. |
(b) | Amounts related to certain land-related leases have indefinite payment periods. The annual obligation of $2 million for these items is included in the 2013 through 2017 columns, respectively. |
Coal | Natural Gas | Nuclear Fuel | Purchased Power(a) | Methane Gas | Other | Total | |||||||||||||||||||||
2013 | $ | 620 | $ | 327 | $ | 36 | $ | 421 | $ | 3 | $ | 156 | $ | 1,563 | |||||||||||||
2014 | 625 | 249 | 89 | 309 | 3 | 159 | 1,434 | ||||||||||||||||||||
2015 | 614 | 136 | 87 | 164 | 4 | 117 | 1,122 | ||||||||||||||||||||
2016 | 644 | 54 | 95 | 78 | 4 | 62 | 937 | ||||||||||||||||||||
2017 | 676 | 34 | 78 | 55 | 5 | 50 | 898 | ||||||||||||||||||||
Thereafter | 245 | 105 | 277 | 687 | 99 | 246 | 1,659 | ||||||||||||||||||||
Total | $ | 3,424 | $ | 905 | $ | 662 | $ | 1,714 | $ | 118 | $ | 790 | $ | 7,613 |
(a) | The purchased power amounts includes Ameren Illinois' 20-year agreements for renewable energy credits that were entered into in December 2010 with various renewable energy suppliers. The agreements contain a provision that allows Ameren Illinois to reduce the quantity purchased in the event that Ameren Illinois would not be able to recover the costs associated with the renewable energy credits. |
• | 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 or changes to existing standards for ozone, fine particulates, SO2, and NOx emissions; |
• | additional 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 technology; |
• | 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 the 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 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 | ||||||||||
$ | 257 | $ | 339 | $ | 257 |
(a) | Recorded liability represents the estimated minimum probable obligations, as no other amount within the range provided a better estimate. |
Ameren | Ameren Missouri | Ameren Illinois | Total(a) | |||
4 | 74 | 96 | 121 |
(a) | Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants. |
Year ended | ||||||||||||
2012 | 2011 | 2010 | ||||||||||
Operating revenues | $ | 1,047 | $ | 1,278 | $ | 1,369 | ||||||
Operating expenses | (3,478 | ) | (a) | (1,048 | ) | (1,578 | ) | (b) | ||||
Operating income (loss) | (2,431 | ) | 230 | (209 | ) | |||||||
Other income (loss) | — | 1 | 2 | |||||||||
Interest charges | (56 | ) | (64 | ) | (83 | ) | ||||||
Income (loss) before income taxes | (2,487 | ) | 167 | (290 | ) | |||||||
Income tax (expense) benefit | 989 | (65 | ) | (51 | ) | |||||||
Income (loss) from discontinued operations, net of taxes | $ | (1,498 | ) | $ | 102 | $ | (341 | ) |
(a) | 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. In addition, includes a noncash pretax asset impairment charge of $1.95 billion to reduce the carrying values of all the AER coal and natural gas-fired energy centers, except the Joppa coal-fired energy center, to their estimated fair values, under held and used accounting guidance, as a result of the decision in December 2012 that Ameren intends to exit the Merchant Generation business. |
(b) | Includes a noncash pretax goodwill impairment charge of $420 million representing all the goodwill assigned to Ameren's Merchant Generation reporting unit as a result of proposed and pending environmental regulations which were expected to result in a significant increase in capital and operations and maintenance expenditures for the energy centers held by AER. Also, includes a $36 million noncash pretax asset impairment charge to reduce the carrying value of the Medina Valley energy center to its estimated fair value and a noncash pretax intangible asset impairment charge of $68 million to reduce existing SO2 emission allowances to their estimated fair value. |
December 31, 2012 | December 31, 2011 | ||||||
Current assets of discontinued operations | |||||||
Cash and cash equivalents | $ | 25 | $ | 7 | |||
Accounts receivable and unbilled revenue | 102 | 108 | |||||
Materials and supplies | 134 | 162 | |||||
Mark-to-market derivative assets | 102 | 65 | |||||
Property and plant, net | 748 | 3,279 | |||||
Accumulated deferred income taxes, net | 385 | — | |||||
Other assets | 104 | 97 | |||||
Total current assets of discontinued operations | $ | 1,600 | $ | 3,718 | |||
Current liabilities of discontinued operations | |||||||
Accounts payable and other current obligations | $ | 133 | $ | 134 | |||
Mark-to-market derivative liabilities | 63 | 39 | |||||
Long-term debt, net | 824 | 824 | |||||
Accumulated deferred income taxes, net | — | 583 | |||||
Asset retirement obligations | 78 | 64 | |||||
Pension and other postretirement benefits | 40 | 92 | |||||
Other liabilities | 28 | 26 | |||||
Total current liabilities of discontinued operations | $ | 1,166 | $ | 1,762 | |||
Accumulated other comprehensive income (loss)(a) | $ | 19 | $ | (31 | ) | ||
Noncontrolling interest(b) | $ | 8 | $ | 7 |
(a) | Accumulated other comprehensive income related to discontinued operations remains in “Accumulated other comprehensive loss” on Ameren’s December 31, 2012 and 2011, consolidated balance sheets. This balance relates to New AER assets and liabilities that will be realized or removed from Ameren’s consolidated 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 December 31, 2012 and 2011, consolidated balance sheets. This noncontrolling interest will be removed from Ameren’s consolidated balance sheet at the closing of the New AER divestiture. |
Required Ratio | Actual Ratio | ||
Interest coverage ratio- restricted payment (a) | ≥1.75 | 2.6 | |
Interest coverage ratio- additional indebtedness (b) | ≥2.50 | 2.6 | |
Debt-to-capital ratio- additional indebtedness (b) | ≤60% | 44 | % |
(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. |
2012 | 2011 | 2010 | |||||||
Long-Lived Assets and Related Charges | $ | — | $ | 123 | $ | 64 |
Ameren Missouri | Ameren Illinois | Other | Intersegment Eliminations | Consolidated | ||||||||||||||||
2012 | ||||||||||||||||||||
External revenues | $ | 3,252 | $ | 2,524 | $ | 5 | $ | — | $ | 5,781 | ||||||||||
Intersegment revenues | 20 | 1 | 3 | (24 | ) | — | ||||||||||||||
Depreciation and amortization | 440 | 221 | 6 | — | 667 | |||||||||||||||
Interest and dividend income | 32 | — | — | — | 32 | |||||||||||||||
Interest charges | 223 | 129 | 39 | — | 391 | |||||||||||||||
Income taxes (benefit) | 252 | 94 | (37 | ) | — | 309 | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 416 | 141 | (39 | ) | — | 518 | ||||||||||||||
Capital expenditures | 595 | 442 | 26 | — | 1,063 | |||||||||||||||
Total assets | 13,043 | 7,282 | 1,228 | (934 | ) | 20,619 | (a) | |||||||||||||
2011 | ||||||||||||||||||||
External revenues | $ | 3,360 | $ | 2,784 | $ | 83 | $ | — | $ | 6,227 | ||||||||||
Intersegment revenues | 23 | 3 | 3 | (29 | ) | — | ||||||||||||||
Depreciation and amortization | 408 | 215 | 23 | — | 646 | |||||||||||||||
Interest and dividend income | 30 | 1 | — | — | 31 | |||||||||||||||
Interest charges | 209 | 136 | 42 | — | 387 | |||||||||||||||
Income taxes (benefit) | 161 | 127 | (43 | ) | — | 245 | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 287 | 193 | (62 | ) | — | 418 | ||||||||||||||
Capital expenditures | 550 | 351 | (20 | ) | (b) | — | 881 | |||||||||||||
Total assets | 12,757 | 7,213 | 1,211 | (1,176 | ) | 20,005 | (a) | |||||||||||||
2010 | ||||||||||||||||||||
External revenues | $ | 3,180 | $ | 3,012 | $ | 77 | $ | — | $ | 6,269 | ||||||||||
Intersegment revenues | 17 | 2 | — | (19 | ) | — | ||||||||||||||
Depreciation and amortization | 382 | 210 | 35 | — | 627 | |||||||||||||||
Interest and dividend income | 31 | 1 | — | — | 32 | |||||||||||||||
Interest charges | 213 | 143 | 59 | — | 415 | |||||||||||||||
Income taxes (benefit) | 199 | 137 | (62 | ) | — | 274 | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 364 | 208 | (89 | ) | — | 483 | ||||||||||||||
Capital expenditures | 624 | 281 | 36 | — | 941 | |||||||||||||||
Total assets | 12,504 | 7,406 | 1,354 | (1,541 | ) | 19,723 | (a) |
(a) | Excludes "Current assets for discontinued operations." See Note 16 - Divestiture Transactions and Discontinued Operations for additional information. |
(b) | Includes the elimination of intercompany transfers. |
2012 | 2011 | ||||||||||||||||||||||||||||||||
Quarter ended (a) | March 31 | June 30 | September 30 | December 31 | March 31 | June 30 | September 30 | December 31 | |||||||||||||||||||||||||
Operating Revenues | $ | 1,412 | $ | 1,402 | $ | 1,709 | $ | 1,258 | $ | 1,597 | $ | 1,458 | $ | 1,876 | $ | 1,296 | |||||||||||||||||
Operating Income (b) | 158 | 344 | 578 | 111 | 156 | 270 | 494 | 91 | |||||||||||||||||||||||||
Net Income (Loss) | (403 | ) | 210 | 374 | (1,155 | ) | 74 | 139 | 287 | 26 | |||||||||||||||||||||||
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations | $ | 37 | $ | 161 | $ | 305 | $ | 15 | $ | 38 | $ | 116 | $ | 265 | $ | (1 | ) | ||||||||||||||||
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations (c) | (440 | ) | 50 | 69 | (1,171 | ) | 33 | 22 | 20 | 26 | |||||||||||||||||||||||
Net Income (Loss) Attributable to Ameren Corporation | $ | (403 | ) | $ | 211 | $ | 374 | $ | (1,156 | ) | $ | 71 | $ | 138 | $ | 285 | $ | 25 | |||||||||||||||
Earnings (Loss) per Common Share - Basic and Diluted - Continuing Operations | $ | 0.15 | $ | 0.66 | $ | 1.26 | $ | 0.06 | $ | 0.16 | $ | 0.48 | $ | 1.10 | $ | (0.01 | ) | ||||||||||||||||
Earnings (Loss) per Common Share - Basic and Diluted - Discontinued Operations | (1.81 | ) | 0.21 | 0.28 | (4.82 | ) | 0.13 | 0.09 | 0.08 | 0.11 | |||||||||||||||||||||||
Earnings (Loss) per Common Share - Basic and Diluted | $ | (1.66 | ) | $ | 0.87 | $ | 1.54 | $ | (4.76 | ) | $ | 0.29 | $ | 0.57 | $ | 1.18 | $ | 0.10 |
(a) | The sum of quarterly amounts, including per share amounts, may not equal amounts reported for year-to-date periods. This is due to the effects of rounding and changes in the number of weighted-average shares outstanding each period. |
(b) | Includes pretax "Impairment and other charges" of $123 million recorded to continuing operations during the year ended December 31, 2011. See Note 17 - Impairment and Other Charges for additional information. |
(c) | Includes a pretax asset impairment charge of $2.578 billion recorded to discontinued operations during the year ended December 31, 2012. See Note 16 - Divestiture Transactions and Discontinued Operations for additional information. |
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Years Ended December 31, 2012, 2011 and 2010 | |||||||||||
(In millions) | 2012 | 2011 | 2010 | ||||||||
Operating revenues | $ | — | $ | — | $ | — | |||||
Operating expenses | 17 | 13 | 19 | ||||||||
Operating loss | (17 | ) | (13 | ) | (19 | ) | |||||
Equity in earnings of subsidiaries | 548 | 451 | 525 | ||||||||
Interest income from affiliates | 3 | 5 | 8 | ||||||||
Miscellaneous expense | 4 | 4 | 3 | ||||||||
Interest charges | 39 | 41 | 56 | ||||||||
Income tax (benefit) | (27 | ) | (20 | ) | (28 | ) | |||||
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations | 518 | 418 | 483 | ||||||||
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations | (1,492 | ) | 101 | (344 | ) | ||||||
Net income (Loss) Attributable to Ameren Corporation | $ | (974 | ) | $ | 519 | $ | 139 | ||||
Net Income (Loss) Attributable to Ameren Corporation - Continuing Operations | $ | 518 | $ | 418 | $ | 483 | |||||
Other Comprehensive Income (Loss), Net of Taxes: | |||||||||||
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $(6), $(14), and $7, respectively | (8 | ) | (19 | ) | 10 | ||||||
Comprehensive Income from Continuing Operations | 510 | 399 | 493 | ||||||||
Net Income (Loss) Attributable to Ameren Corporation - Discontinued Operations | (1,492 | ) | 101 | (344 | ) | ||||||
Other Comprehensive Income (Loss) from Discontinued Operations, Net of Income Taxes | 50 | (14 | ) | (14 | ) | ||||||
Comprehensive Income (Loss) from Discontinued Operations | (1,442 | ) | 87 | (358 | ) | ||||||
Comprehensive Income (Loss) Attributable to Ameren Corporation | $ | (932 | ) | $ | 486 | $ | 135 |
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED BALANCE SHEET | |||||||
(In millions) | December 31, 2012 | December 31, 2011 | |||||
Assets: | |||||||
Cash and cash equivalents | $ | 23 | $ | 3 | |||
Advances to money pool | 316 | 340 | |||||
Accounts and notes receivable - affiliates | 31 | 57 | |||||
Other current assets | 49 | — | |||||
Total current assets | 419 | 400 | |||||
Investments in subsidiaries - continuing operations | 6,288 | 6,327 | |||||
Investments in subsidiaries - discontinued operations | (326 | ) | 1,155 | ||||
Note receivable - affiliates | 462 | 425 | |||||
Other non-current assets | 320 | 333 | |||||
Total assets | $ | 7,163 | $ | 8,640 | |||
Liabilities and Stockholders’ Equity: | |||||||
Short-term debt | $ | — | $ | 148 | |||
Accounts payable - affiliates | 10 | 13 | |||||
Other current liabilities | 33 | 62 | |||||
Total current liabilities | 43 | 223 | |||||
Long-term debt | 424 | 424 | |||||
Other deferred credits and liabilities | 80 | 74 | |||||
Total liabilities | 547 | 721 | |||||
Commitments and Contingencies | |||||||
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 | 5,616 | 5,598 | |||||
Retained earnings | 1,006 | 2,369 | |||||
Accumulated other comprehensive income (loss) | (8 | ) | (50 | ) | |||
Total stockholders’ equity | 6,616 | 7,919 | |||||
Total liabilities and stockholders’ equity | $ | 7,163 | $ | 8,640 |
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT AMEREN CORPORATION CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2012, 2011 and 2010 | |||||||||||
(In millions) | 2012 | 2011 | 2010 | ||||||||
Net cash flows provided by operating activities | $ | 532 | $ | 804 | $ | 241 | |||||
Cash flows from investing activities: | |||||||||||
Money pool advances, net | 24 | (276 | ) | 18 | |||||||
Notes receivable - affiliates, net | (20 | ) | 358 | 242 | |||||||
Investments in subsidiaries | (2 | ) | (94 | ) | (13 | ) | |||||
Distributions from subsidiaries | 21 | 3 | 1 | ||||||||
Other | (5 | ) | (5 | ) | — | ||||||
Net cash flows provided by (used in) investing activities | 18 | (14 | ) | 248 | |||||||
Cash flows from financing activities: | |||||||||||
Dividends on common stock | (382 | ) | (375 | ) | (368 | ) | |||||
Short-term debt and credit facility borrowings, net | (148 | ) | (481 | ) | (221 | ) | |||||
Issuances of common stock | — | 65 | 80 | ||||||||
Net cash flows used in financing activities | (530 | ) | (791 | ) | (509 | ) | |||||
Net change in cash and cash equivalents | $ | 20 | $ | (1 | ) | $ | (20 | ) | |||
Cash and cash equivalents at beginning of year | 3 | 4 | 24 | ||||||||
Cash and cash equivalents at the end of year | $ | 23 | $ | 3 | $ | 4 | |||||
Cash dividends received from consolidated subsidiaries | $ | 610 | $ | 730 | $ | 368 | |||||
Noncash financing activity – dividends on common stock | $ | (7 | ) | $ | — | $ | — |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010 | |||||||||||||||||||
(in millions) | |||||||||||||||||||
Column A | Column B | Column C | Column D | Column E | |||||||||||||||
Description | Balance at Beginning of Period | (1) Charged to Costs and Expenses | (2) Charged to Other Accounts(a) | Deductions(b) | Balance at End of Period | ||||||||||||||
Ameren: | |||||||||||||||||||
Deducted from assets - allowance for doubtful accounts: | |||||||||||||||||||
2012 | $ | 20 | $ | 30 | $ | 2 | $ | 35 | $ | 17 | |||||||||
2011 | 22 | 41 | — | 43 | 20 | ||||||||||||||
2010 | 24 | 32 | — | 34 | 22 | ||||||||||||||
Deferred tax valuation allowance: | |||||||||||||||||||
2012 | $ | 1 | $ | 1 | $ | — | $ | — | $ | 2 | |||||||||
2011 | 1 | — | — | — | 1 | ||||||||||||||
2010 | — | 1 | — | — | 1 |
(a) | Uncollectible account reserve associated with receivables purchased by Ameren Illinois from alternative retail electric suppliers as required by the Illinois Public Utility Act. |
(b) | Uncollectible accounts charged off, less recoveries. |
Nuclear Decommissioning Trust Fund Investments (Fair Value And The Gross Unrealized Losses Of The Available-For-Sale Securities Held In Nuclear Decommissioning Trust Fund) (Details) (USD $)
In Millions, unless otherwise specified |
Dec. 31, 2012
|
---|---|
Nuclear Decommissioning Trust Fund Investments [Line Items] | |
Less than 12 months, fair value | $ 24 |
Less than 12 months, gross unrealized losses | 1 |
12 months or greater, fair value | 14 |
12 months or greater, gross unrealized losses | 10 |
Total, fair value | 38 |
Total, gross unrealized losses | 11 |
Debt Securities [Member]
|
|
Nuclear Decommissioning Trust Fund Investments [Line Items] | |
Less than 12 months, fair value | 17 |
Total, fair value | 17 |
Equity Securities [Member]
|
|
Nuclear Decommissioning Trust Fund Investments [Line Items] | |
Less than 12 months, fair value | 7 |
Less than 12 months, gross unrealized losses | 1 |
12 months or greater, fair value | 14 |
12 months or greater, gross unrealized losses | 10 |
Total, fair value | 21 |
Total, gross unrealized losses | $ 11 |
Derivative Financial Instruments (Derivatives That Qualify For Regulatory Deferral) (Details) (USD $)
In Millions, unless otherwise specified |
12 Months Ended | |
---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
|
Derivative [Line Items] | ||
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets | $ (112) | $ 51 |
Fuel Oils [Member]
|
||
Derivative [Line Items] | ||
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets | (15) | |
Natural Gas [Member]
|
||
Derivative [Line Items] | ||
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets | 84 | (26) |
Power [Member]
|
||
Derivative [Line Items] | ||
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets | (180) | 80 |
Uranium [Member]
|
||
Derivative [Line Items] | ||
Gain (Loss) RecognizedIn Regulatory Liabilitiesor Regulatory Assets | $ (1) | $ (3) |
Fair Value Measurements (Narrative) (Details) (USD $)
In Millions, unless otherwise specified |
Dec. 31, 2012
|
Dec. 31, 2011
|
---|---|---|
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Counterparty default risk liability valuation adjustment related to derivative contracts | $ 7 | $ 4 |
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities Resulting From Temporary Differences) (Details) (USD $)
In Millions, unless otherwise specified |
Dec. 31, 2012
|
Dec. 31, 2011
|
||||
---|---|---|---|---|---|---|
Income Taxes [Line Items] | ||||||
Plant related | $ 3,512 | $ 3,162 | ||||
Deferred intercompany tax gain/basis step-up | 39 | 54 | ||||
Regulatory assets, net | 73 | 73 | ||||
Deferred employee benefit costs | (323) | (320) | ||||
Purchase accounting | (27) | (28) | ||||
ARO | (17) | (12) | ||||
Other | (251) | [1] | (217) | [1] | ||
Total net accumulated deferred income tax liabilities | 3,006 | 2,712 | ||||
Current assets | $ 170 | $ 98 | ||||
|
Retirement Benefits (Target Allocation Of The Plans' Asset Categories) (Details)
|
12 Months Ended | |
---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
|
Pension Benefits [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Percentage of Plan Assets | 100.00% | 100.00% |
Pension Benefits [Member] | Cash and cash equivalents [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 0.00% | |
Maximum Target Allocation | 5.00% | |
Percentage of Plan Assets | 2.00% | 2.00% |
Pension Benefits [Member] | Total equity [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 50.00% | |
Maximum Target Allocation | 60.00% | |
Percentage of Plan Assets | 54.00% | 51.00% |
Pension Benefits [Member] | U.S. large capitalization [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 29.00% | |
Maximum Target Allocation | 39.00% | |
Percentage of Plan Assets | 34.00% | 33.00% |
Pension Benefits [Member] | U.S. small and mid-capitalization [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 2.00% | |
Maximum Target Allocation | 12.00% | |
Percentage of Plan Assets | 7.00% | 7.00% |
Pension Benefits [Member] | International and emerging markets [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 9.00% | |
Maximum Target Allocation | 19.00% | |
Percentage of Plan Assets | 13.00% | 11.00% |
Pension Benefits [Member] | Debt securities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 35.00% | |
Maximum Target Allocation | 45.00% | |
Percentage of Plan Assets | 39.00% | 42.00% |
Pension Benefits [Member] | Real estate [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 0.00% | |
Maximum Target Allocation | 9.00% | |
Percentage of Plan Assets | 4.00% | 4.00% |
Pension Benefits [Member] | Private equity [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 0.00% | |
Maximum Target Allocation | 4.00% | |
Percentage of Plan Assets | 1.00% | 1.00% |
Postretirement Benefits [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Percentage of Plan Assets | 100.00% | 100.00% |
Postretirement Benefits [Member] | Cash and cash equivalents [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 0.00% | |
Maximum Target Allocation | 10.00% | |
Percentage of Plan Assets | 4.00% | 4.00% |
Postretirement Benefits [Member] | Total equity [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 55.00% | |
Maximum Target Allocation | 65.00% | |
Percentage of Plan Assets | 62.00% | 59.00% |
Postretirement Benefits [Member] | U.S. large capitalization [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 33.00% | |
Maximum Target Allocation | 43.00% | |
Percentage of Plan Assets | 40.00% | 38.00% |
Postretirement Benefits [Member] | U.S. small and mid-capitalization [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 3.00% | |
Maximum Target Allocation | 13.00% | |
Percentage of Plan Assets | 8.00% | 8.00% |
Postretirement Benefits [Member] | International [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 10.00% | |
Maximum Target Allocation | 20.00% | |
Percentage of Plan Assets | 14.00% | 13.00% |
Postretirement Benefits [Member] | Debt securities [Member]
|
||
Defined Benefit Plan Disclosure [Line Items] | ||
Minimum Target Allocation | 30.00% | |
Maximum Target Allocation | 40.00% | |
Percentage of Plan Assets | 34.00% | 37.00% |
Retirement Benefits (Assumptions Used To Determine Net Periodic Benefit Cost) (Details)
|
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2012
|
Dec. 31, 2011
|
Dec. 31, 2010
|
|
Pension Benefits [Member]
|
|||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate at measurement date | 4.50% | 5.25% | 5.75% |
Expected return on plan assets | 7.75% | 8.00% | 8.00% |
Increase in future compensation | 3.50% | 3.50% | 3.50% |
Medical cost trend rate (initial) | 0.00% | 0.00% | 0.00% |
Medical cost trend rate (ultimate) | 0.00% | 0.00% | 0.00% |
Years to ultimate rate | 0 years | 0 years | 0 years |
Postretirement Benefits [Member]
|
|||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate at measurement date | 4.50% | 5.25% | 5.75% |
Expected return on plan assets | 7.50% | 7.75% | 8.00% |
Increase in future compensation | 3.50% | 3.50% | 3.50% |
Medical cost trend rate (initial) | 5.50% | 6.00% | 6.50% |
Medical cost trend rate (ultimate) | 5.00% | 5.00% | 5.00% |
Years to ultimate rate | 1 year | 2 years | 3 years |
Fair Value Measurements
|
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2012
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about market risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Authoritative accounting guidance established a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels: Level 1: Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities are primarily exchange-traded derivatives and assets, including cash and cash equivalents and listed equity securities, such as those held in Ameren Missouri’s nuclear decommissioning trust fund. The market approach is used to measure the fair value of equity securities held in Ameren Missouri's nuclear decommissioning trust fund. Equity securities in this fund are representative of the S&P 500 index, excluding securities of Ameren Corporation, owners and/or operators of nuclear power plants and the trustee and investment managers. The S&P 500 index comprises stocks of large capitalization companies. Level 2: Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in Ameren Missouri’s nuclear decommissioning trust fund, including corporate bonds and other fixed-income securities, United States treasury and agency securities, and certain over-the-counter derivative instruments, including natural gas and financial power transactions. Fixed income securities are valued using prices from independent industry recognized data vendors who provide values that are either exchange based or matrix based. The fair value measurements of fixed income securities classified as Level 2 are based on inputs other than quoted prices that are observable for the asset or liability. Examples are matrix pricing, market corroborated pricing, and inputs such as yield curves and indices. Level 2 fixed income securities in the nuclear decommissioning trust fund are primarily corporate bonds, asset-backed securities and United States agency bonds. Derivative instruments classified as Level 2 are valued by corroborated observable inputs, such as pricing services or prices from similar instruments that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint. Natural gas derivative contracts are valued based upon exchange closing prices without significant unobservable adjustments. Power derivatives contracts are valued based upon the use of multiple forward prices provided by third parties. The prices are averaged and shaped to a monthly profile when needed without significant unobservable adjustments. Level 3: Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued by internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable. We value Level 3 instruments by using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, an evaluation of all sources is performed to identify any anomalies or potential errors. Note 17 - Impairment and Other Charges describes Ameren's use of significant unobservable inputs, which are Level 3 inputs, to estimate the fair value of Merchant Generation's long-lived assets. We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to fair value measurements. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3. The following table describes the valuation techniques and unobservable inputs for the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the period ended December 31, 2012:
In accordance with applicable authoritative accounting guidance, we consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). The guidance also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing, as well as any potential credit enhancements, into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. We recorded no gains or losses related to valuation adjustments for counterparty default risk in 2012, 2011, or 2010. The counterparty default risk liability valuation adjustment related to derivative contracts totaled $7 million and $4 million, as of December 31, 2012, and 2011, respectively. The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2012:
The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2011:
The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy as of December 31, 2012, and 2011:
Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers out of Level 3 into Level 2 for natural gas derivatives were due to management previously using broker quotations to estimate the fair value of natural gas contracts and changing to estimates based upon exchange closing prices without significant unobservable adjustments in the first quarter 2012. Estimates of fair value based on exchange closing prices are deemed to be a more accurate approximation of natural gas prices. Transfers between Level 2 and Level 3 for power derivatives and between Level 1 and Level 3 for fuel oils were primarily caused by changes in availability of financial trades observable on electronic exchanges between the period ended December 31, 2012 and the previous reporting period ended December 31, 2011. Any reclassifications are reported as transfers out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur. For the years ended December 31, 2012, and 2011, there were no transfers between Level 1 and Level 2 related to derivative commodity contracts. The following table summarizes all transfers between fair value hierarchy levels related to derivative commodity contracts for the years ended December 31, 2012, and 2011:
See Note 11 - Retirement Benefits for the fair value hierarchy tables detailing Ameren’s pension and postretirement plan assets as of December 31, 2012, as well as a table summarizing the changes in Level 3 plan assets during 2012. See Note 17 - Impairment and Other Charges for the fair value hierarchy discussion related to Ameren's impairment charges. The Ameren Companies’ carrying amounts of cash and cash equivalents approximate fair value because of the short-term nature of these instruments and are considered to be Level 1 in the fair value hierarchy. Ameren's carrying amounts of investments in debt securities related to the two CTs from the city of Bowling Green and Audrain County approximate fair value. These investments are classified as held-to-maturity. These investments are considered Level 2 in the fair value hierarchy as they are valued based on similar market transactions. Short-term borrowings, which are composed of Ameren issued commercial paper, also approximate fair value because of their short-term nature. Short-term borrowings are considered to be Level 2 in the fair value hierarchy as they are valued based on market rates for similar market transactions. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issuances for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments, which fair value measurement is considered Level 2 in the fair value hierarchy. The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 2012, and 2011:
|
Rate And Regulatory Matters (Narrative) (Details) (USD $)
|
1 Months Ended | 12 Months Ended | 1 Months Ended | 1 Months Ended | 12 Months Ended | 12 Months Ended | 60 Months Ended | 0 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 1 Months Ended | 1 Months Ended | 12 Months Ended | 1 Months Ended | ||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Nov. 30, 2012
design
|
Dec. 31, 2012
design
|
Dec. 31, 2011
|
Dec. 31, 2010
|
Jun. 30, 2008
FERC Relicensing [Member]
Taum Sauk Energy Center [Member]
|
Dec. 31, 2012
Union Electric Company [Member]
New Nuclear Energy Center COL [Member]
|
Apr. 30, 2011
Union Electric Company [Member]
FAC Prudence Review [Member]
|
Dec. 31, 2012
Union Electric Company [Member]
FAC Prudence Review [Member]
|
Feb. 29, 2012
Union Electric Company [Member]
FAC Prudence Review [Member]
|
Dec. 31, 2012
Union Electric Company [Member]
Entergy Refund [Member]
|
Dec. 31, 2005
Union Electric Company [Member]
Pending FERC Case [Member]
Power Purchase Agreement With Entergy Arkansas [Member]
|
Jul. 13, 2011
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
Dec. 31, 2012
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
May 31, 2010
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
account
|
Jan. 31, 2009
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
Dec. 31, 2012
Union Electric Company [Member]
Final Rate Order [Member]
MEEIA [Member]
Electric Distribution [Member]
|
Jul. 13, 2011
Union Electric Company [Member]
Accounting Authority Order Request [Member]
FAC Prudence Review [Member]
|
Dec. 31, 2012
Ameren Illinois Company [Member]
customer
|
Dec. 31, 2012
Ameren Illinois Company [Member]
Wholesale Distribution Rate Case [Member]
|
Jan. 31, 2011
Ameren Illinois Company [Member]
Wholesale Distribution Rate Case [Member]
|
Dec. 31, 2012
Ameren Illinois Company [Member]
IEIMA [Member]
|
Dec. 31, 2012
Ameren Illinois Company [Member]
IEIMA [Member]
Smart Grid [Member]
|
Mar. 31, 2013
Ameren Illinois Company [Member]
Final Rate Order [Member]
IEIMA [Member]
Electric Distribution [Member]
|
Dec. 31, 2012
Ameren Illinois Company [Member]
Final Rate Order [Member]
IEIMA [Member]
Electric Distribution [Member]
|
Jan. 31, 2013
Ameren Illinois Company [Member]
Pending Rate Case [Member]
Gas Distribution [Member]
|
Dec. 31, 2012
ATXI [Member]
Potential Transmission Project Investments Through 2019 [Member]
project
|
Dec. 31, 2012
Energy Infrastructure Investments and Other Nonfuel Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
Dec. 31, 2012
Pension and Other Post-Employment Benefit Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
Dec. 31, 2012
Amortization of Regulatory Asset [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
Dec. 31, 2012
Net Base Fuel Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
Jul. 13, 2011
Net Base Fuel Costs [Member]
Union Electric Company [Member]
Final Rate Order [Member]
Electric Distribution [Member]
|
Dec. 31, 2012
FAC [Member]
Union Electric Company [Member]
|
Dec. 31, 2012
Maximum [Member]
Union Electric Company [Member]
New Nuclear Energy Center COL [Member]
|
Jan. 31, 2013
Maximum [Member]
Ameren Illinois Company [Member]
Pending Rate Case [Member]
Gas Distribution [Member]
|
Dec. 31, 2012
Minimum [Member]
Union Electric Company [Member]
New Nuclear Energy Center COL [Member]
|
Jan. 31, 2013
Minimum [Member]
Ameren Illinois Company [Member]
Pending Rate Case [Member]
Gas Distribution [Member]
|
Dec. 31, 2012
Pending FERC Case [Member]
Ameren Illinois Company [Member]
customer
|
|
Rate And Regulatory Matters [Line Items] | |||||||||||||||||||||||||||||||||||||
Cash and cash equivalents | $ 184,000,000 | $ 248,000,000 | $ 538,000,000 | $ 16,000,000 | $ 21,000,000 | ||||||||||||||||||||||||||||||||
Disallowed capitalized costs associated with rebuilt Taum Sauk energy center | 89,000,000 | ||||||||||||||||||||||||||||||||||||
Authorized increase in revenue from utility service | 173,000,000 | 260,000,000 | 230,000,000 | 80,000,000 | 96,000,000 | 10,000,000 | 6,000,000 | 84,000,000 | 52,000,000 | ||||||||||||||||||||||||||||
Number of industrial customers who received a stay from Circuit Court | 4 | ||||||||||||||||||||||||||||||||||||
Utility revenue increase requested | 11,000,000 | 50,000,000 | |||||||||||||||||||||||||||||||||||
Loss Contingency, Settlement Agreement, Number of Wholesale Customers | 4 | ||||||||||||||||||||||||||||||||||||
Number of Wholesale Customers | 9 | 5 | |||||||||||||||||||||||||||||||||||
Rate of return on common equity | 9.80% | 10.40% | |||||||||||||||||||||||||||||||||||
Percent of capital structure composed of equity | 52.30% | 51.80% | |||||||||||||||||||||||||||||||||||
Rate base | 6,800,000,000 | 1,100,000,000 | |||||||||||||||||||||||||||||||||||
Percentage of Fixed non-volumetric customer charge | 85.00% | 80.00% | |||||||||||||||||||||||||||||||||||
Investments in Power and Distribution Projects, Number of Projects | 3 | ||||||||||||||||||||||||||||||||||||
Energy Efficiency program spending | 147,000,000 | ||||||||||||||||||||||||||||||||||||
Number of years approved | 3 years | 10 years | |||||||||||||||||||||||||||||||||||
Percentage of Project Lost Revenue Included in Rates | 90.00% | ||||||||||||||||||||||||||||||||||||
Remaining Percentage of Projected Lost Revenue | 10.00% | ||||||||||||||||||||||||||||||||||||
Incentive Award if Energy Efficiency Goals Are Achieved | 19,000,000 | ||||||||||||||||||||||||||||||||||||
Achieved Percentage of Energy Efficiency Earnings For Incentive Award | 100.00% | ||||||||||||||||||||||||||||||||||||
Incentive Award if Energy Efficiency Goals Are Achieved, Period | 3 years | ||||||||||||||||||||||||||||||||||||
Minimum Percentage of Energy Efficiency Goal Achievement For Company To Be Eligible For Incentive Award | 70.00% | ||||||||||||||||||||||||||||||||||||
Sharing level for FAC | 95.00% | 95.00% | |||||||||||||||||||||||||||||||||||
Revenue requirement transferred from net fuel cost to other nonfuel costs | 33,000,000 | ||||||||||||||||||||||||||||||||||||
Request to defer fixed costs not recovered from Noranda, amount | 36,000,000 | ||||||||||||||||||||||||||||||||||||
Revenue Requirement | 779,000,000 | 764,000,000 | |||||||||||||||||||||||||||||||||||
Authorized Decrease In Revenue From Utility Service | 55,000,000 | 15,000,000 | |||||||||||||||||||||||||||||||||||
Regulatory liabilities | 1,589,000,000 | 1,502,000,000 | 55,000,000 | ||||||||||||||||||||||||||||||||||
Time required to complete FAC prudence reviews, in months | 18 months | ||||||||||||||||||||||||||||||||||||
Contested Amounts Under FAC | 18,000,000 | 26,000,000 | |||||||||||||||||||||||||||||||||||
Current regulatory liabilities | 100,000,000 | 133,000,000 | 8,000,000 | ||||||||||||||||||||||||||||||||||
Proceeds from Legal Settlements | 31,000,000 | ||||||||||||||||||||||||||||||||||||
Purchased power | 780,000,000 | 952,000,000 | 1,122,000,000 | 24,000,000 | 25,000,000 | ||||||||||||||||||||||||||||||||
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs | 2 | ||||||||||||||||||||||||||||||||||||
Department of Energy, Investing Funding Support, Period | 5 years | ||||||||||||||||||||||||||||||||||||
Department of Energy, Investing Funding Support, Number of Small Modular Reactor Designs Awarded | 1 | ||||||||||||||||||||||||||||||||||||
Other Nonoperating Income | 70,000,000 | 68,000,000 | 88,000,000 | 5,000,000 | |||||||||||||||||||||||||||||||||
Reduction To Under-recovered Asset | 2,000,000 | ||||||||||||||||||||||||||||||||||||
Number Of Years COL is Valid For | 40 years | ||||||||||||||||||||||||||||||||||||
Interest Expense | 391,000,000 | 387,000,000 | 415,000,000 | 1,000,000 | |||||||||||||||||||||||||||||||||
Capital investments | $ 69,000,000 | $ 360,000,000 | $ 1,300,000,000 | $ 100,000,000 | $ 80,000,000 | ||||||||||||||||||||||||||||||||
Number of years for proposed relicensing application filed with FERC | 40 years |
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