ý | Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the Quarterly Period Ended June 30, 2014 |
¨ | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to |
Commission File Number | Exact name of registrant as specified in its charter; State of Incorporation; Address and Telephone Number | IRS Employer Identification No. | ||
1-14756 | Ameren Corporation | 43-1723446 | ||
(Missouri Corporation) | ||||
1901 Chouteau Avenue | ||||
St. Louis, Missouri 63103 | ||||
(314) 621-3222 | ||||
1-2967 | Union Electric Company | 43-0559760 | ||
(Missouri Corporation) | ||||
1901 Chouteau Avenue | ||||
St. Louis, Missouri 63103 | ||||
(314) 621-3222 | ||||
1-3672 | Ameren Illinois Company | 37-0211380 | ||
(Illinois Corporation) | ||||
6 Executive Drive | ||||
Collinsville, Illinois 62234 | ||||
(618) 343-8150 |
Ameren Corporation | Yes | ý | No | ¨ | ||||
Union Electric Company | Yes | ý | No | ¨ | ||||
Ameren Illinois Company | Yes | ý | No | ¨ |
Ameren Corporation | Yes | ý | No | ¨ | ||||
Union Electric Company | Yes | ý | No | ¨ | ||||
Ameren Illinois Company | Yes | ý | No | ¨ |
Large Accelerated Filer | Accelerated Filer | Non-Accelerated Filer | Smaller Reporting Company | |||||
Ameren Corporation | ý | ¨ | ¨ | ¨ | ||||
Union Electric Company | ¨ | ¨ | ý | ¨ | ||||
Ameren Illinois Company | ¨ | ¨ | ý | ¨ |
Ameren Corporation | Yes | ¨ | No | ý | ||||
Union Electric Company | Yes | ¨ | No | ý | ||||
Ameren Illinois Company | Yes | ¨ | No | ý |
Ameren Corporation | Common stock, $0.01 par value per share - 242,634,798 | |
Union Electric Company | Common stock, $5 par value per share, held by Ameren Corporation - 102,123,834 | |
Ameren Illinois Company | Common stock, no par value, held by Ameren Corporation - 25,452,373 |
Page | ||
Item 1. | ||
Union Electric Company (d/b/a Ameren Missouri) | ||
Ameren Illinois Company (d/b/a Ameren Illinois) | ||
Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 1. | ||
Item 1A. | ||
Item 2. | ||
Item 6. | ||
• | regulatory, judicial, or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the complaint cases filed by Noranda and 37 residential customers with the MoPSC in February 2014; Ameren |
• | the effect of Ameren Illinois participating in a performance-based formula ratemaking process under the IEIMA, including the direct relationship between Ameren Illinois' return on common equity and 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 potential extension of the IEIMA after its current sunset provision at the end of 2017, and any changes to the performance-based formula ratemaking process or required financial commitments; |
• | the effects of Ameren Illinois' expected participation, beginning in 2015, in the regulatory framework provided by the state of Illinois' Natural Gas Consumer, Safety and Reliability Act, which allows for the use of a rider to recover costs of certain natural gas infrastructure investments made between rate cases; |
• | the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at either the state or federal levels and the implementation of deregulation; |
• | changes in laws and other governmental actions, including monetary, fiscal, and tax policies; |
• | 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; |
• | the timing of increasing capital expenditure and operating expense requirements and our ability to timely 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 our ability to recover the costs for such commodities; |
• | the effectiveness of our risk management strategies and the use of financial and derivative instruments; |
• | 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 may have an adverse effect on the cost or availability of capital, including short-term credit and liquidity; |
• | our assessment of our liquidity; |
• | 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 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 returns in a timely fashion, if at all; |
• | the extent to which Ameren Missouri prevails in its claim against an insurer 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 and unplanned outages, and decommissioning costs; |
• | the effects of strategic initiatives, including mergers, acquisitions and divestitures, and any related tax implications; |
• | the impact of current environmental regulations and new, more stringent or changing requirements, including those related to greenhouse gases, other emissions and discharges, cooling water intake structures, CCR, and energy efficiency, that are enacted over time and that could limit or terminate the operation of certain of our energy centers, increase our costs or investment requirements, result in an impairment of our assets, cause us to sell 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 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 Missouri's energy centers or required to satisfy Ameren Missouri’s energy sales; |
• | the inability of Dynegy and IPH to satisfy their indemnity and other obligations to Ameren in connection with the divestiture of New AER to IPH; |
• | legal and administrative proceedings; and |
• | acts of sabotage, war, terrorism, cyber attacks or intentionally disruptive acts. |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Operating Revenues: | |||||||||||||||
Electric | $ | 1,235 | $ | 1,228 | $ | 2,341 | $ | 2,316 | |||||||
Gas | 184 | 175 | 672 | 562 | |||||||||||
Total operating revenues | 1,419 | 1,403 | 3,013 | 2,878 | |||||||||||
Operating Expenses: | |||||||||||||||
Fuel | 198 | 213 | 402 | 426 | |||||||||||
Purchased power | 111 | 121 | 223 | 272 | |||||||||||
Gas purchased for resale | 79 | 72 | 383 | 302 | |||||||||||
Other operations and maintenance | 412 | 447 | 832 | 846 | |||||||||||
Depreciation and amortization | 183 | 178 | 364 | 353 | |||||||||||
Taxes other than income taxes | 114 | 111 | 241 | 233 | |||||||||||
Total operating expenses | 1,097 | 1,142 | 2,445 | 2,432 | |||||||||||
Operating Income | 322 | 261 | 568 | 446 | |||||||||||
Other Income and Expenses: | |||||||||||||||
Miscellaneous income | 21 | 16 | 39 | 31 | |||||||||||
Miscellaneous expense | 4 | 5 | 13 | 13 | |||||||||||
Total other income | 17 | 11 | 26 | 18 | |||||||||||
Interest Charges | 89 | 100 | 181 | 201 | |||||||||||
Income Before Income Taxes | 250 | 172 | 413 | 263 | |||||||||||
Income Taxes | 99 | 66 | 163 | 101 | |||||||||||
Income from Continuing Operations | 151 | 106 | 250 | 162 | |||||||||||
Loss from Discontinued Operations, Net of Taxes (Note 12) | (1 | ) | (10 | ) | (2 | ) | (209 | ) | |||||||
Net Income (Loss) | 150 | 96 | 248 | (47 | ) | ||||||||||
Less: Net Income from Continuing Operations Attributable to Noncontrolling Interests | 1 | 1 | 3 | 3 | |||||||||||
Net Income (Loss) Attributable to Ameren Corporation: | |||||||||||||||
Continuing Operations | 150 | 105 | 247 | 159 | |||||||||||
Discontinued Operations | (1 | ) | (10 | ) | (2 | ) | (209 | ) | |||||||
Net Income (Loss) Attributable to Ameren Corporation | $ | 149 | $ | 95 | $ | 245 | $ | (50 | ) | ||||||
Earnings (Loss) per Common Share – Basic: | |||||||||||||||
Continuing Operations | $ | 0.62 | $ | 0.44 | $ | 1.02 | $ | 0.66 | |||||||
Discontinued Operations | (0.01 | ) | (0.05 | ) | (0.01 | ) | (0.87 | ) | |||||||
Earnings (Loss) per Common Share – Basic | $ | 0.61 | $ | 0.39 | $ | 1.01 | $ | (0.21 | ) | ||||||
Dividends per Common Share | $ | 0.40 | $ | 0.40 | $ | 0.80 | $ | 0.80 | |||||||
Average Common Shares Outstanding – Basic | 242.6 | 242.6 | 242.6 | 242.6 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Income from Continuing Operations | $ | 151 | $ | 106 | $ | 250 | $ | 162 | |||||||
Other Comprehensive Income, Net of Taxes | |||||||||||||||
Pension and other postretirement benefit plan activity, net of income taxes of $3, $8, $3 and $8, respectively | 3 | 10 | 3 | 10 | |||||||||||
Comprehensive Income from Continuing Operations | 154 | 116 | 253 | 172 | |||||||||||
Less: Comprehensive Income from Continuing Operations Attributable to Noncontrolling Interests | 1 | 1 | 3 | 3 | |||||||||||
Comprehensive Income from Continuing Operations Attributable to Ameren Corporation | 153 | 115 | 250 | 169 | |||||||||||
Loss from Discontinued Operations, Net of Taxes | (1 | ) | (10 | ) | (2 | ) | (209 | ) | |||||||
Other Comprehensive Loss from Discontinued Operations, Net of Taxes | — | (4 | ) | — | (11 | ) | |||||||||
Comprehensive Loss from Discontinued Operations Attributable to Ameren Corporation | (1 | ) | (14 | ) | (2 | ) | (220 | ) | |||||||
Comprehensive Income (Loss) Attributable to Ameren Corporation | $ | 152 | $ | 101 | $ | 248 | $ | (51 | ) |
June 30, 2014 | December 31, 2013 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 46 | $ | 30 | |||
Accounts receivable – trade (less allowance for doubtful accounts of $23 and $18, respectively) | 454 | 404 | |||||
Unbilled revenue | 299 | 304 | |||||
Miscellaneous accounts and notes receivable | 213 | 196 | |||||
Materials and supplies | 491 | 526 | |||||
Current regulatory assets | 202 | 156 | |||||
Current accumulated deferred income taxes, net | 177 | 106 | |||||
Other current assets | 68 | 85 | |||||
Assets of discontinued operations (Note 12) | 15 | 165 | |||||
Total current assets | 1,965 | 1,972 | |||||
Property and Plant, Net | 16,726 | 16,205 | |||||
Investments and Other Assets: | |||||||
Nuclear decommissioning trust fund | 523 | 494 | |||||
Goodwill | 411 | 411 | |||||
Intangible assets | 19 | 22 | |||||
Regulatory assets | 1,213 | 1,240 | |||||
Other assets | 731 | 698 | |||||
Total investments and other assets | 2,897 | 2,865 | |||||
TOTAL ASSETS | $ | 21,588 | $ | 21,042 | |||
LIABILITIES AND EQUITY | |||||||
Current Liabilities: | |||||||
Current maturities of long-term debt | $ | 119 | $ | 534 | |||
Short-term debt | 793 | 368 | |||||
Accounts and wages payable | 575 | 806 | |||||
Taxes accrued | 132 | 55 | |||||
Interest accrued | 92 | 86 | |||||
Current regulatory liabilities | 218 | 216 | |||||
Other current liabilities | 350 | 351 | |||||
Liabilities of discontinued operations (Note 12) | 33 | 45 | |||||
Total current liabilities | 2,312 | 2,461 | |||||
Long-term Debt, Net | 5,825 | 5,504 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes, net | 3,526 | 3,250 | |||||
Accumulated deferred investment tax credits | 60 | 63 | |||||
Regulatory liabilities | 1,784 | 1,705 | |||||
Asset retirement obligations | 380 | 369 | |||||
Pension and other postretirement benefits | 463 | 466 | |||||
Other deferred credits and liabilities | 524 | 538 | |||||
Total deferred credits and other liabilities | 6,737 | 6,391 | |||||
Commitments and Contingencies (Notes 2, 9, 10 and 12) | |||||||
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 | 5,607 | 5,632 | |||||
Retained earnings | 957 | 907 | |||||
Accumulated other comprehensive income | 6 | 3 | |||||
Total Ameren Corporation stockholders’ equity | 6,572 | 6,544 | |||||
Noncontrolling Interests | 142 | 142 | |||||
Total equity | 6,714 | 6,686 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 21,588 | $ | 21,042 |
AMEREN CORPORATION | |||||||
CONSOLIDATED STATEMENT OF CASH FLOWS | |||||||
(Unaudited) (In millions) | |||||||
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
Cash Flows From Operating Activities: | |||||||
Net income (loss) | $ | 248 | $ | (47 | ) | ||
Loss from discontinued operations, net of taxes | 2 | 209 | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||
Depreciation and amortization | 349 | 334 | |||||
Amortization of nuclear fuel | 47 | 29 | |||||
Amortization of debt issuance costs and premium/discounts | 11 | 12 | |||||
Deferred income taxes and investment tax credits, net | 178 | 70 | |||||
Allowance for equity funds used during construction | (16 | ) | (16 | ) | |||
Stock-based compensation costs | 15 | 14 | |||||
Other | (8 | ) | 18 | ||||
Changes in assets and liabilities: | |||||||
Receivables | (62 | ) | (92 | ) | |||
Materials and supplies | 35 | 77 | |||||
Accounts and wages payable | (180 | ) | (75 | ) | |||
Taxes accrued | 68 | 67 | |||||
Assets, other | (68 | ) | 49 | ||||
Liabilities, other | 3 | 9 | |||||
Pension and other postretirement benefits | 21 | 36 | |||||
Counterparty collateral, net | 15 | 35 | |||||
Net cash provided by operating activities – continuing operations | 658 | 729 | |||||
Net cash provided by (used in) operating activities – discontinued operations | (4 | ) | 39 | ||||
Net cash provided by operating activities | 654 | 768 | |||||
Cash Flows From Investing Activities: | |||||||
Capital expenditures | (883 | ) | (575 | ) | |||
Nuclear fuel expenditures | (26 | ) | (25 | ) | |||
Purchases of securities – nuclear decommissioning trust fund | (290 | ) | (97 | ) | |||
Sales and maturities of securities – nuclear decommissioning trust fund | 283 | 89 | |||||
Proceeds from note receivable – Marketing Company | 70 | — | |||||
Contributions to note receivable – Marketing Company | (78 | ) | — | ||||
Other | 2 | 2 | |||||
Net cash used in investing activities – continuing operations | (922 | ) | (606 | ) | |||
Net cash provided by (used in) investing activities – discontinued operations | 152 | (31 | ) | ||||
Net cash used in investing activities | (770 | ) | (637 | ) | |||
Cash Flows From Financing Activities: | |||||||
Dividends on common stock | (194 | ) | (194 | ) | |||
Dividends paid to noncontrolling interest holders | (3 | ) | (3 | ) | |||
Short-term debt, net | 425 | 25 | |||||
Redemptions and maturities of long-term debt | (692 | ) | — | ||||
Issuances of long-term debt | 598 | — | |||||
Capital issuance costs | (4 | ) | — | ||||
Advances received for construction | 2 | 7 | |||||
Net cash provided by (used in) financing activities – continuing operations | 132 | (165 | ) | ||||
Net cash used in financing activities – discontinued operations | — | — | |||||
Net cash provided by (used in) financing activities | 132 | (165 | ) | ||||
Net change in cash and cash equivalents | 16 | (34 | ) | ||||
Cash and cash equivalents at beginning of year | 30 | 209 | |||||
Cash and cash equivalents at end of period | 46 | 175 | |||||
Less cash and cash equivalents at end of period – discontinued operations | — | 25 | |||||
Cash and cash equivalents at end of period – continuing operations | $ | 46 | $ | 150 | |||
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Operating Revenues: | |||||||||||||||
Electric | $ | 871 | $ | 860 | $ | 1,620 | $ | 1,592 | |||||||
Gas | 28 | 29 | 96 | 93 | |||||||||||
Other | 1 | — | 1 | — | |||||||||||
Total operating revenues | 900 | 889 | 1,717 | 1,685 | |||||||||||
Operating Expenses: | |||||||||||||||
Fuel | 198 | 213 | 402 | 426 | |||||||||||
Purchased power | 28 | 41 | 61 | 67 | |||||||||||
Gas purchased for resale | 11 | 11 | 51 | 48 | |||||||||||
Other operations and maintenance | 222 | 253 | 449 | 474 | |||||||||||
Depreciation and amortization | 117 | 113 | 233 | 224 | |||||||||||
Taxes other than income taxes | 81 | 79 | 159 | 156 | |||||||||||
Total operating expenses | 657 | 710 | 1,355 | 1,395 | |||||||||||
Operating Income | 243 | 179 | 362 | 290 | |||||||||||
Other Income and Expenses: | |||||||||||||||
Miscellaneous income | 16 | 14 | 30 | 28 | |||||||||||
Miscellaneous expense | 2 | 3 | 6 | 8 | |||||||||||
Total other income | 14 | 11 | 24 | 20 | |||||||||||
Interest Charges | 54 | 56 | 106 | 116 | |||||||||||
Income Before Income Taxes | 203 | 134 | 280 | 194 | |||||||||||
Income Taxes | 76 | 49 | 105 | 68 | |||||||||||
Net Income | 127 | 85 | 175 | 126 | |||||||||||
Other Comprehensive Income | — | — | — | — | |||||||||||
Comprehensive Income | $ | 127 | $ | 85 | $ | 175 | $ | 126 | |||||||
Net Income | $ | 127 | $ | 85 | $ | 175 | $ | 126 | |||||||
Preferred Stock Dividends | 1 | 1 | 2 | 2 | |||||||||||
Net Income Available to Common Stockholder | $ | 126 | $ | 84 | $ | 173 | $ | 124 |
June 30, 2014 | December 31, 2013 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 28 | $ | 1 | |||
Accounts receivable – trade (less allowance for doubtful accounts of $7 and $5, respectively) | 217 | 191 | |||||
Accounts receivable – affiliates | 2 | 1 | |||||
Unbilled revenue | 214 | 168 | |||||
Miscellaneous accounts and notes receivable | 81 | 57 | |||||
Materials and supplies | 352 | 352 | |||||
Current regulatory assets | 141 | 118 | |||||
Other current assets | 82 | 71 | |||||
Total current assets | 1,117 | 959 | |||||
Property and Plant, Net | 10,599 | 10,452 | |||||
Investments and Other Assets: | |||||||
Nuclear decommissioning trust fund | 523 | 494 | |||||
Intangible assets | 19 | 22 | |||||
Regulatory assets | 529 | 534 | |||||
Other assets | 416 | 443 | |||||
Total investments and other assets | 1,487 | 1,493 | |||||
TOTAL ASSETS | $ | 13,203 | $ | 12,904 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current Liabilities: | |||||||
Current maturities of long-term debt | $ | 119 | $ | 109 | |||
Borrowings from money pool | 61 | 105 | |||||
Short-term debt | 185 | — | |||||
Accounts and wages payable | 195 | 387 | |||||
Accounts payable – affiliates | 16 | 30 | |||||
Taxes accrued | 157 | 220 | |||||
Interest accrued | 73 | 57 | |||||
Current regulatory liabilities | 39 | 57 | |||||
Other current liabilities | 101 | 82 | |||||
Total current liabilities | 946 | 1,047 | |||||
Long-term Debt, Net | 3,885 | 3,648 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes, net | 2,613 | 2,524 | |||||
Accumulated deferred investment tax credits | 57 | 59 | |||||
Regulatory liabilities | 1,099 | 1,041 | |||||
Asset retirement obligations | 378 | 366 | |||||
Pension and other postretirement benefits | 172 | 189 | |||||
Other deferred credits and liabilities | 42 | 37 | |||||
Total deferred credits and other liabilities | 4,361 | 4,216 | |||||
Commitments and Contingencies (Notes 2, 8, 9 and 10) | |||||||
Stockholders’ Equity: | |||||||
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding | 511 | 511 | |||||
Other paid-in capital, principally premium on common stock | 1,560 | 1,560 | |||||
Preferred stock not subject to mandatory redemption | 80 | 80 | |||||
Retained earnings | 1,860 | 1,842 | |||||
Total stockholders’ equity | 4,011 | 3,993 | |||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 13,203 | $ | 12,904 |
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
Cash Flows From Operating Activities: | |||||||
Net income | $ | 175 | $ | 126 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | 220 | 208 | |||||
Amortization of nuclear fuel | 47 | 29 | |||||
FAC prudence review charge | — | 23 | |||||
Amortization of debt issuance costs and premium/discounts | 4 | 4 | |||||
Deferred income taxes and investment tax credits, net | 61 | 13 | |||||
Allowance for equity funds used during construction | (15 | ) | (14 | ) | |||
Changes in assets and liabilities: | |||||||
Receivables | (97 | ) | (155 | ) | |||
Materials and supplies | — | 28 | |||||
Accounts and wages payable | (163 | ) | (119 | ) | |||
Taxes accrued | (65 | ) | 79 | ||||
Assets, other | (5 | ) | 61 | ||||
Liabilities, other | 39 | 37 | |||||
Pension and other postretirement benefits | 11 | 18 | |||||
Net cash provided by operating activities | 212 | 338 | |||||
Cash Flows From Investing Activities: | |||||||
Capital expenditures | (375 | ) | (273 | ) | |||
Nuclear fuel expenditures | (26 | ) | (25 | ) | |||
Money pool advances, net | — | 24 | |||||
Purchases of securities – nuclear decommissioning trust fund | (290 | ) | (97 | ) | |||
Sales and maturities of securities – nuclear decommissioning trust fund | 283 | 89 | |||||
Other | (5 | ) | (3 | ) | |||
Net cash used in investing activities | (413 | ) | (285 | ) | |||
Cash Flows From Financing Activities: | |||||||
Dividends on common stock | (155 | ) | (180 | ) | |||
Dividends on preferred stock | (2 | ) | (2 | ) | |||
Short-term debt, net | 185 | — | |||||
Money pool borrowings, net | (44 | ) | — | ||||
Maturities of long-term debt | (104 | ) | — | ||||
Issuances of long-term debt | 350 | — | |||||
Capital issuance costs | (2 | ) | — | ||||
Net cash provided by (used in) financing activities | 228 | (182 | ) | ||||
Net change in cash and cash equivalents | 27 | (129 | ) | ||||
Cash and cash equivalents at beginning of year | 1 | 148 | |||||
Cash and cash equivalents at end of period | $ | 28 | $ | 19 |
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Operating Revenues: | |||||||||||||||
Electric | $ | 364 | $ | 368 | $ | 717 | $ | 728 | |||||||
Gas | 155 | 146 | 576 | 470 | |||||||||||
Other | — | 2 | — | 2 | |||||||||||
Total operating revenues | 519 | 516 | 1,293 | 1,200 | |||||||||||
Operating Expenses: | |||||||||||||||
Purchased power | 86 | 80 | 167 | 207 | |||||||||||
Gas purchased for resale | 67 | 61 | 331 | 254 | |||||||||||
Other operations and maintenance | 195 | 196 | 395 | 372 | |||||||||||
Depreciation and amortization | 64 | 62 | 127 | 123 | |||||||||||
Taxes other than income taxes | 32 | 30 | 78 | 72 | |||||||||||
Total operating expenses | 444 | 429 | 1,098 | 1,028 | |||||||||||
Operating Income | 75 | 87 | 195 | 172 | |||||||||||
Other Income and Expenses: | |||||||||||||||
Miscellaneous income | 5 | 2 | 8 | 3 | |||||||||||
Miscellaneous expense | 1 | 1 | 5 | 4 | |||||||||||
Total other income (expense) | 4 | 1 | 3 | (1 | ) | ||||||||||
Interest Charges | 29 | 34 | 59 | 65 | |||||||||||
Income Before Income Taxes | 50 | 54 | 139 | 106 | |||||||||||
Income Taxes | 21 | 22 | 56 | 42 | |||||||||||
Net Income | 29 | 32 | 83 | 64 | |||||||||||
Other Comprehensive Loss, Net of Taxes: | |||||||||||||||
Pension and other postretirement benefit plan activity, net of income taxes (benefit) of $-, $-, $(1) and $(1), respectively | (1 | ) | (1 | ) | (2 | ) | (2 | ) | |||||||
Comprehensive Income | $ | 28 | $ | 31 | $ | 81 | $ | 62 | |||||||
Net Income | $ | 29 | $ | 32 | $ | 83 | $ | 64 | |||||||
Preferred Stock Dividends | 1 | 1 | 2 | 2 | |||||||||||
Net Income Available to Common Stockholder | $ | 28 | $ | 31 | $ | 81 | $ | 62 |
June 30, 2014 | December 31, 2013 | ||||||
ASSETS | |||||||
Current Assets: | |||||||
Cash and cash equivalents | $ | 2 | $ | 1 | |||
Accounts receivable – trade (less allowance for doubtful accounts of $16 and $13, respectively) | 221 | 201 | |||||
Unbilled revenue | 85 | 135 | |||||
Miscellaneous accounts receivable | 7 | 13 | |||||
Materials and supplies | 138 | 174 | |||||
Current regulatory assets | 61 | 38 | |||||
Current accumulated deferred income taxes, net | 77 | 45 | |||||
Other current assets | 14 | 26 | |||||
Total current assets | 605 | 633 | |||||
Property and Plant, Net | 5,882 | 5,589 | |||||
Investments and Other Assets: | |||||||
Goodwill | 411 | 411 | |||||
Regulatory assets | 677 | 701 | |||||
Other assets | 144 | 120 | |||||
Total investments and other assets | 1,232 | 1,232 | |||||
TOTAL ASSETS | $ | 7,719 | $ | 7,454 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current Liabilities: | |||||||
Short-term debt | $ | 105 | $ | — | |||
Borrowings from money pool | — | 56 | |||||
Accounts and wages payable | 209 | 243 | |||||
Accounts payable – affiliates | 25 | 18 | |||||
Taxes accrued | 18 | 23 | |||||
Customer deposits | 75 | 79 | |||||
Current environmental remediation | 47 | 43 | |||||
Current regulatory liabilities | 179 | 159 | |||||
Other current liabilities | 121 | 150 | |||||
Total current liabilities | 779 | 771 | |||||
Long-term Debt, Net | 1,940 | 1,856 | |||||
Deferred Credits and Other Liabilities: | |||||||
Accumulated deferred income taxes, net | 1,205 | 1,116 | |||||
Accumulated deferred investment tax credits | 4 | 4 | |||||
Regulatory liabilities | 685 | 664 | |||||
Pension and other postretirement benefits | 215 | 197 | |||||
Environmental remediation | 212 | 232 | |||||
Other deferred credits and liabilities | 152 | 166 | |||||
Total deferred credits and other liabilities | 2,473 | 2,379 | |||||
Commitments and Contingencies (Notes 2, 8 and 9) | |||||||
Stockholders’ Equity: | |||||||
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding | — | — | |||||
Other paid-in capital | 1,965 | 1,965 | |||||
Preferred stock not subject to mandatory redemption | 62 | 62 | |||||
Retained earnings | 491 | 410 | |||||
Accumulated other comprehensive income | 9 | 11 | |||||
Total stockholders’ equity | 2,527 | 2,448 | |||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 7,719 | $ | 7,454 |
Six Months Ended June 30, | |||||||
2014 | 2013 | ||||||
Cash Flows From Operating Activities: | |||||||
Net income | $ | 83 | $ | 64 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | 125 | 121 | |||||
Amortization of debt issuance costs and premium/discounts | 6 | 7 | |||||
Deferred income taxes and investment tax credits, net | 58 | 61 | |||||
Other | (4 | ) | (4 | ) | |||
Changes in assets and liabilities: | |||||||
Receivables | 36 | 62 | |||||
Materials and supplies | 36 | 50 | |||||
Accounts and wages payable | 2 | 46 | |||||
Taxes accrued | (5 | ) | (6 | ) | |||
Assets, other | (61 | ) | (4 | ) | |||
Liabilities, other | 3 | (18 | ) | ||||
Pension and other postretirement benefits | 7 | 15 | |||||
Counterparty collateral, net | 15 | 32 | |||||
Net cash provided by operating activities | 301 | 426 | |||||
Cash Flows From Investing Activities: | |||||||
Capital expenditures | (436 | ) | (283 | ) | |||
Other | 4 | 4 | |||||
Net cash used in investing activities | (432 | ) | (279 | ) | |||
Cash Flows From Financing Activities: | |||||||
Dividends on common stock | — | (30 | ) | ||||
Dividends on preferred stock | (2 | ) | (2 | ) | |||
Short-term debt, net | 105 | — | |||||
Money pool borrowings, net | (56 | ) | (24 | ) | |||
Redemptions of long-term debt | (163 | ) | — | ||||
Issuances of long-term debt | 248 | — | |||||
Capital issuance costs | (2 | ) | — | ||||
Advances received for construction | 2 | 7 | |||||
Net cash provided by (used in) financing activities | 132 | (49 | ) | ||||
Net change in cash and cash equivalents | 1 | 98 | |||||
Cash and cash equivalents at beginning of year | 1 | — | |||||
Cash and cash equivalents at end of period | $ | 2 | $ | 98 |
• | Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission, and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Ameren Missouri supplies electric service to 1.2 million customers and natural gas service to 127,000 customers. |
• | Ameren Illinois Company, doing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren Illinois supplies electric service to 1.2 million customers and natural gas service to 807,000 customers. |
Performance Share Units | |||||
Share Units | Weighted-average Fair Value Per Share Unit at Grant Date | ||||
Nonvested at January 1, 2014 | 1,218,544 | $ | 33.23 | ||
Granted(a) | 683,591 | 38.90 | |||
April Grants(b) | 38,559 | 50.34 | |||
Forfeitures | (65,847 | ) | 33.82 | ||
Vested(c) | (116,297 | ) | 38.81 | ||
Nonvested at June 30, 2014 | 1,758,550 | $ | 35.42 |
(a) | Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in 2014 under the 2006 Incentive Plan. |
(b) | In April 2014, certain executive officers were granted additional share units under the 2006 Incentive Plan and the 2014 Incentive Plan. The significant assumptions used to calculate fair value included a prorated three-year risk-free rate ranging from 0.76% to 0.79%, volatility of 12% to 18% for the peer group, and Ameren’s attainment of a three-year average earnings per share threshold during the performance period. |
(c) | Share units vested due to the attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period. |
Three Months | Six Months | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Ameren Missouri | $ | — | $ | — | $ | 6 | $ | (a) | |||||||
Ameren Illinois | 3 | 3 | 6 | 7 | |||||||||||
Ameren | $ | 3 | $ | 3 | $ | 12 | $ | 7 |
(a) | Less than $1 million. |
Three Months | Six Months | ||||||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||||||
Ameren Missouri | $ | 39 | $ | 38 | $ | 73 | $ | 71 | |||||||
Ameren Illinois | 11 | 11 | 37 | 33 | |||||||||||
Ameren | $ | 50 | $ | 49 | $ | 110 | $ | 104 |
June 30, 2014 | December 31, 2013 | ||||||
Ameren | $ | 94 | $ | 90 | |||
Ameren Missouri | 34 | 31 | |||||
Ameren Illinois | — | (1 | ) |
June 30, 2014 | December 31, 2013 | ||||||
Ameren | $ | 55 | $ | 54 | |||
Ameren Missouri | 3 | 3 | |||||
Ameren Illinois | (1 | ) | — |
Three Months | Six Months | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Noncontrolling interests, beginning of period | $ | 142 | $ | 151 | (a) | $ | 142 | $ | 151 | (a) | ||||||
Net income from continuing operations attributable to noncontrolling interests | 1 | 1 | 3 | 3 | ||||||||||||
Dividends paid to noncontrolling interest holders | (1 | ) | (1 | ) | (3 | ) | (3 | ) | ||||||||
Noncontrolling interests, end of period | $ | 142 | $ | 151 | (a) | $ | 142 | $ | 151 | (a) |
(a) | Included the 20% EEI ownership interest not owned by Ameren prior to the divestiture of New AER to IPH. Prior to the divestiture of New AER, the assets and liabilities of EEI were consolidated in Ameren’s balance sheet at a 100% ownership level and were included in “Assets of discontinued operations” and “Liabilities of discontinued operations.” The divestiture of New AER, which included EEI, was completed in the fourth quarter of 2013. See Note 12 - Divestiture Transactions and Discontinued Operations for additional information. |
June 30, 2014 | December 31, 2013 | ||||||
Ameren (parent) | $ | 503 | $ | 368 | |||
Ameren Missouri | 185 | — | |||||
Ameren Illinois | 105 | — | |||||
Ameren Consolidated | $ | 793 | $ | 368 |
Ameren (parent) | Ameren Missouri | Ameren Illinois | Ameren Consolidated | |||||||||||
2014 | ||||||||||||||
Average daily commercial paper outstanding | $ | 328 | $ | 146 | $ | 242 | $ | 607 | ||||||
Weighted-average interest rate | 0.32 | % | 0.31 | % | 0.32 | % | 0.32 | % | ||||||
Peak commercial paper during period(a) | $ | 503 | $ | 495 | $ | 300 | $ | 907 | ||||||
Peak interest rate | 0.35 | % | 0.70 | % | 0.34 | % | 0.70 | % | ||||||
2013 | ||||||||||||||
Average daily commercial paper outstanding | $ | 13 | $ | — | $ | — | $ | 13 | ||||||
Weighted-average interest rate | 0.54 | % | — | % | — | % | 0.54 | % | ||||||
Peak commercial paper during period(a) | $ | 78 | $ | — | $ | — | $ | 78 | ||||||
Peak interest rate | 0.85 | % | — | % | — | % | 0.85 | % |
(a) | The timing of peak commercial paper issuances varies by company, and therefore the peak amounts presented by company might not equal the Ameren Consolidated peak commercial paper issuances for the period. |
Environmental improvement and pollution control revenue bonds | Principal Amount | ||
5.90% Series 1993 due 2023(a) | $ | 32 | |
5.70% 1994A Series due 2024(a) | 36 | ||
5.95% 1993 Series C-1 due 2026 | 35 | ||
5.70% 1993 Series C-2 due 2026 | 8 | ||
5.40% 1998A Series due 2028 | 19 | ||
5.40% 1998B Series due 2028 | 33 | ||
Total amount redeemed | $ | 163 |
(a) | Less than $1 million principal amount of the bonds remain outstanding after redemption. |
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 | 4.7 | $ | 3,168 | ≥2.5 | 130.8 | $ | 2,508 | |||||||
Ameren Illinois | ≥2.0 | 6.7 | 3,780 | (d) | ≥1.5 | 2.4 | 203 | (e) |
(a) | Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds. |
(b) | Amount of bonds issuable based either on required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $833 million and $204 million at Ameren Missouri and Ameren Illinois, respectively. |
(c) | Coverage required on the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. |
(d) | Amount of bonds issuable by Ameren Illinois based on unfunded property additions and retired bonds solely under the former IP mortgage indenture. |
(e) | Preferred stock issuable is restricted by the amount of preferred stock that is currently authorized by Ameren Illinois’ articles of incorporation. |
Three Months | Six Months | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Ameren:(a) | ||||||||||||||||
Miscellaneous income: | ||||||||||||||||
Allowance for equity funds used during construction | $ | 9 | $ | 8 | $ | 16 | $ | 16 | ||||||||
Interest income on industrial development revenue bonds | 7 | 7 | 14 | 14 | ||||||||||||
Interest income | 2 | 1 | 5 | 1 | ||||||||||||
Other | 3 | — | 4 | — | ||||||||||||
Total miscellaneous income | $ | 21 | $ | 16 | $ | 39 | $ | 31 | ||||||||
Miscellaneous expense: | ||||||||||||||||
Donations | $ | 1 | $ | 1 | $ | 6 | $ | 5 | ||||||||
Other | 3 | 4 | 7 | 8 | ||||||||||||
Total miscellaneous expense | $ | 4 | $ | 5 | $ | 13 | $ | 13 | ||||||||
Ameren Missouri: | ||||||||||||||||
Miscellaneous income: | ||||||||||||||||
Allowance for equity funds used during construction | $ | 8 | $ | 7 | $ | 15 | $ | 14 | ||||||||
Interest income on industrial development revenue bonds | 7 | 7 | 14 | 14 | ||||||||||||
Interest income | 1 | — | 1 | — | ||||||||||||
Total miscellaneous income | $ | 16 | $ | 14 | $ | 30 | $ | 28 | ||||||||
Miscellaneous expense: | ||||||||||||||||
Donations | $ | 1 | $ | 1 | $ | 3 | $ | 3 | ||||||||
Other | 1 | 2 | 3 | 5 | ||||||||||||
Total miscellaneous expense | $ | 2 | $ | 3 | $ | 6 | $ | 8 | ||||||||
Ameren Illinois: | ||||||||||||||||
Miscellaneous income: | ||||||||||||||||
Allowance for equity funds used during construction | $ | 1 | $ | 1 | $ | 1 | $ | 2 | ||||||||
Interest income | 1 | 1 | 3 | 1 | ||||||||||||
Other | 3 | — | 4 | — | ||||||||||||
Total miscellaneous income | $ | 5 | $ | 2 | $ | 8 | $ | 3 | ||||||||
Miscellaneous expense: | ||||||||||||||||
Donations | $ | — | $ | — | $ | 3 | $ | 3 | ||||||||
Other | 1 | 1 | 2 | 1 | ||||||||||||
Total miscellaneous expense | $ | 1 | $ | 1 | $ | 5 | $ | 4 |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
• | an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices; |
• | market values of natural gas and uranium inventories that differ from the cost of those commodities in inventory; and |
• | actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays. |
Quantity (in millions, except as indicated) | ||||||||||||
2014 | 2013 | |||||||||||
Commodity | Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils (in gallons)(a) | 51 | (b) | 51 | 66 | (b) | 66 | ||||||
Natural gas (in mmbtu) | 25 | 101 | 126 | 28 | 108 | 136 | ||||||
Power (in megawatthours) | 1 | 11 | 12 | 3 | 11 | 14 | ||||||
Uranium (pounds in thousands) | 627 | (b) | 627 | 796 | (b) | 796 |
(a) | Fuel oils consist of ultra-low-sulfur diesel, on-highway diesel, and crude oil. |
(b) | Not applicable. |
Balance Sheet Location | Ameren Missouri | Ameren Illinois | Ameren | ||||||||||
2014 | |||||||||||||
Fuel oils | Other current assets | $ | 5 | $ | — | $ | 5 | ||||||
Other assets | 2 | — | 2 | ||||||||||
Natural gas | Other current assets | 1 | 3 | 4 | |||||||||
Other assets | — | 1 | 1 | ||||||||||
Power | Other current assets | 22 | — | 22 | |||||||||
Total assets | $ | 30 | $ | 4 | $ | 34 | |||||||
Fuel oils | Other current liabilities | $ | 2 | $ | — | $ | 2 | ||||||
Other deferred credits and liabilities | 1 | — | 1 | ||||||||||
Natural gas | Other current liabilities | 4 | 16 | 20 | |||||||||
Other deferred credits and liabilities | 2 | 8 | 10 | ||||||||||
Power | Other current liabilities | 6 | 7 | 13 | |||||||||
Other deferred credits and liabilities | — | 96 | 96 | ||||||||||
Uranium | Other current liabilities | 5 | — | 5 | |||||||||
Other deferred credits and liabilities | 2 | — | 2 | ||||||||||
Total liabilities | $ | 22 | $ | 127 | $ | 149 | |||||||
2013 | |||||||||||||
Fuel oils | Other current assets | $ | 6 | $ | — | $ | 6 | ||||||
Other assets | 3 | — | 3 | ||||||||||
Natural gas | Other current assets | 1 | 1 | 2 | |||||||||
Power | Other current assets | 23 | — | 23 | |||||||||
Total assets | $ | 33 | $ | 1 | $ | 34 | |||||||
Fuel oils | Other current liabilities | $ | 2 | $ | — | $ | 2 | ||||||
Other deferred credits and liabilities | 1 | — | 1 | ||||||||||
Natural gas | Other current liabilities | 5 | 27 | 32 | |||||||||
Other deferred credits and liabilities | 6 | 19 | 25 | ||||||||||
Power | Other current liabilities | 4 | 9 | 13 | |||||||||
Other deferred credits and liabilities | — | 99 | 99 | ||||||||||
Uranium | Other current liabilities | 5 | — | 5 | |||||||||
Other deferred credits and liabilities | 1 | — | 1 | ||||||||||
Total liabilities | $ | 24 | $ | 154 | $ | 178 |
Ameren Missouri | Ameren Illinois | Ameren | |||||||||
2014 | |||||||||||
Fuel oils derivative contracts(a) | $ | 3 | $ | — | $ | 3 | |||||
Natural gas derivative contracts(b) | (5 | ) | (20 | ) | (25 | ) | |||||
Power derivative contracts(c) | 16 | (103 | ) | (87 | ) | ||||||
Uranium derivative contracts(d) | (7 | ) | — | (7 | ) | ||||||
2013 | |||||||||||
Fuel oils derivative contracts | $ | 2 | $ | — | $ | 2 | |||||
Natural gas derivative contracts | (10 | ) | (45 | ) | (55 | ) | |||||
Power derivative contracts | 19 | (108 | ) | (89 | ) | ||||||
Uranium derivative contracts | (6 | ) | — | (6 | ) |
(a) | Represents net gains on fuel oils derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s transportation costs for coal through December 2017, as of June 30, 2014. Current gains deferred as regulatory liabilities include $2 million and $2 million at Ameren and Ameren Missouri, respectively, as of June 30, 2014. Current losses deferred as regulatory assets include $1 million and $1 million at Ameren and Ameren Missouri, respectively, as of June 30, 2014. |
(b) | Represents net losses associated with natural gas derivative contracts. These contracts are a partial hedge of natural gas requirements through October 2019 at Ameren and Ameren Missouri and through October 2017, at Ameren Illinois, in each case as of June 30, 2014. Current gains deferred as regulatory liabilities include $4 million, $1 million, and $3 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2014. Current losses deferred as regulatory assets include $20 million, $4 million, and $16 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2014. |
(c) | Represents net gains (losses) associated with power derivative contracts. These contracts are a partial hedge of power price requirements through May 2032 at Ameren and Ameren Illinois and through December 2015 at Ameren Missouri, in each case as of June 30, 2014. Current gains deferred as regulatory liabilities include $22 million and $22 million at Ameren and Ameren Missouri, respectively, as of June 30, 2014. Current losses deferred as regulatory assets include $13 million, $6 million, and $7 million at Ameren, Ameren Missouri and Ameren Illinois, respectively, as of June 30, 2014. |
(d) | Represents net losses on uranium derivative contracts at Ameren Missouri. These contracts are a partial hedge of Ameren Missouri’s uranium requirements through December 2016, as of June 30, 2014. Current losses deferred as regulatory assets include $5 million and $5 million at Ameren and Ameren Missouri, respectively, as of June 30, 2014. |
Gross Amounts Not Offset in the Balance Sheet | ||||||||||||||||
Commodity Contracts Eligible to be Offset | Gross Amounts Recognized in the Balance Sheet | Derivative Instruments | Cash Collateral Received/Posted(a) | Net Amount | ||||||||||||
2014 | ||||||||||||||||
Assets: | ||||||||||||||||
Ameren Missouri | $ | 30 | $ | 9 | $ | — | $ | 21 | ||||||||
Ameren Illinois | 4 | 3 | — | 1 | ||||||||||||
Ameren | $ | 34 | $ | 12 | $ | — | $ | 22 | ||||||||
Liabilities: | ||||||||||||||||
Ameren Missouri | $ | 22 | $ | 9 | $ | 10 | $ | 3 | ||||||||
Ameren Illinois | 127 | 3 | — | 124 | ||||||||||||
Ameren | $ | 149 | $ | 12 | $ | 10 | $ | 127 | ||||||||
2013 | ||||||||||||||||
Assets: | ||||||||||||||||
Ameren Missouri | $ | 33 | $ | 9 | $ | — | $ | 24 | ||||||||
Ameren Illinois | 1 | 1 | — | — | ||||||||||||
Ameren | $ | 34 | $ | 10 | $ | — | $ | 24 | ||||||||
Liabilities: | ||||||||||||||||
Ameren Missouri | $ | 24 | $ | 9 | $ | 9 | $ | 6 | ||||||||
Ameren Illinois | 154 | 1 | 15 | 138 | ||||||||||||
Ameren | $ | 178 | $ | 10 | $ | 24 | $ | 144 |
(a) | Cash collateral received reduces gross asset balances and is included in “Other current liabilities” and “Other deferred credits and liabilities” on the balance sheet. Cash collateral posted reduces gross liability balances and is included in “Other current assets” and “Other assets” on the balance sheet. |
Aggregate Fair Value of Derivative Liabilities(a) | Cash Collateral Posted | Potential Aggregate Amount of Additional Collateral Required(b) | |||||||||
2014 | |||||||||||
Ameren Missouri | $ | 60 | $ | 2 | $ | 53 | |||||
Ameren Illinois | 65 | — | 59 | ||||||||
Ameren | $ | 125 | $ | 2 | $ | 112 | |||||
2013 | |||||||||||
Ameren Missouri | $ | 70 | $ | 2 | $ | 67 | |||||
Ameren Illinois | 75 | 15 | 55 | ||||||||
Ameren | $ | 145 | $ | 17 | $ | 122 |
(a) | Prior to consideration of master trading and netting agreements and including NPNS and accrual contract exposures. |
(b) | As collateral requirements with certain counterparties are based on master trading and netting agreements, the aggregate amount of additional collateral required to be posted is determined after consideration of the effects of such agreements. |
Fair Value | Weighted Average | ||||||||||
Assets | Liabilities | Valuation Technique(s) | Unobservable Input | Range | |||||||
Level 3 Derivative asset and liability - commodity contracts(a): | |||||||||||
Ameren | Fuel oils | $ | 5 | $ | (3 | ) | Option model | Volatilities(%)(b) | 5 - 34 | 15 | |
Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.25 - 0.91 | 0.63 | ||||||||
Power(e) | 21 | (109 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c) | 22 - 60 | 36 | ||||
Estimated auction price for FTRs($/MW)(b) | (1,716) - 2,024 | 443 | |||||||||
Nodal basis($/MWh)(c) | (6) - 0 | (3) | |||||||||
Counterparty credit risk(%)(c)(d) | 0.25 | (f) | |||||||||
Ameren Missouri and Ameren Illinois credit risk(%)(c)(d) | 0.43 | (f) | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 5 - 6 | 5 | ||||||||
Escalation rate(%)(b)(g) | 2 - 3 | 3 | |||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 | ||||||||
Uranium | — | (7 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 28 - 33 | 29 | ||||
Ameren Missouri | Fuel oils | $ | 5 | $ | (3 | ) | Option model | Volatilities(%)(b) | 5 - 34 | 15 | |
Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.25 - 0.91 | 0.63 | ||||||||
Power(e) | 21 | (6 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c) | 22 - 60 | 48 | ||||
Estimated auction price for FTRs($/MW)(b) | (1,716) - 2,024 | 443 | |||||||||
Nodal basis($/MWh)(c) | (3) - (1) | (2) | |||||||||
Counterparty credit risk(%)(c)(d) | 0.25 | (f) | |||||||||
Ameren Missouri credit risk(%)(c)(d) | 0.43 | (f) | |||||||||
Uranium | — | (7 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 28 - 33 | 29 | ||||
Ameren Illinois | Power(e) | $ | — | $ | (103 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b) | 28 - 46 | 33 | |
Nodal basis($/MWh)(b) | (6) - 0 | (3) | |||||||||
Ameren Illinois credit risk(%)(c)(d) | 0.43 | (f) | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 5 - 6 | 5 | ||||||||
Escalation rate(%)(b)(g) | 2 - 3 | 3 | |||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
(d) | Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances. |
(e) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2018. Valuations beyond 2018 use fundamentally modeled pricing by month for peak and off-peak demand. |
(f) | Not applicable. |
(g) | Escalation rate applies to power prices 2026 and beyond. |
Fair Value | Weighted Average | ||||||||||
Assets | Liabilities | Valuation Technique(s) | Unobservable Input | Range | |||||||
Level 3 Derivative asset and liability – commodity contracts(a): | |||||||||||
Ameren | Fuel oils | $ | 8 | $ | (3 | ) | Option model | Volatilities(%)(b) | 10 - 35 | 16 | |
Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.26 - 2 | 1 | ||||||||
Power(e) | 21 | (110 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c) | 25 - 51 | 32 | ||||
Estimated auction price for FTRs($/MW)(b) | (1,594) - 945 | 305 | |||||||||
Nodal basis($/MWh)(c) | (3) - (1) | (2) | |||||||||
Counterparty credit risk(%)(c)(d) | 0.39 - 0.50 | 0.42 | |||||||||
Ameren Missouri and Ameren Illinois credit risk(%)(c)(d) | 2 | (f) | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 5 | 5 | ||||||||
Escalation rate(%)(b)(g) | 3 - 4 | 4 | |||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 | ||||||||
Uranium | — | (6 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 34 - 41 | 36 | ||||
Ameren Missouri | Fuel oils | $ | 8 | $ | (3 | ) | Option model | Volatilities(%)(b) | 10 - 35 | 16 | |
Discounted cash flow | Counterparty credit risk(%)(c)(d) | 0.26 - 2 | 1 | ||||||||
Power(e) | 21 | (2 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(c) | 25 - 51 | 40 | ||||
Estimated auction price for FTRs($/MW)(b) | (1,594) - 945 | 305 | |||||||||
Nodal basis($/MWh)(c) | (3) - (1) | (2) | |||||||||
Counterparty credit risk(%)(c)(d) | 0.39 - 0.50 | 0.42 | |||||||||
Ameren Missouri credit risk(%)(c)(d) | 2 | (f) | |||||||||
Uranium | — | (6 | ) | Discounted cash flow | Average forward uranium pricing($/pound)(b) | 34 - 41 | 36 | ||||
Ameren Illinois | Power(e) | $ | — | $ | (108 | ) | Discounted cash flow | Average forward peak and off-peak pricing - forwards/swaps($/MWh)(b) | 27 - 36 | 30 | |
Nodal basis($/MWh)(b) | (4) - 0 | (2) | |||||||||
Ameren Illinois credit risk(%)(c)(d) | 2 | (f) | |||||||||
Fundamental energy production model | Estimated future gas prices($/mmbtu)(b) | 4 - 5 | 5 | ||||||||
Escalation rate(%)(b)(g) | 3 - 4 | 4 | |||||||||
Contract price allocation | Estimated renewable energy credit costs($/credit)(b) | 5 - 7 | 6 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement. |
(c) | Generally, significant increases (decreases) in this input in isolation would result in a significantly lower (higher) fair value measurement. |
(d) | Counterparty credit risk is applied only to counterparties with derivative asset balances. Ameren Missouri and Ameren Illinois credit risk is applied only to counterparties with derivative liability balances. |
(e) | Power valuations use visible third-party pricing evaluated by month for peak and off-peak demand through 2017. Valuations beyond 2017 use fundamentally modeled pricing by month for peak and off-peak demand. |
(f) | Not applicable. |
(g) | Escalation rate applies to power prices 2026 and beyond. |
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | |||||||||||||||
Assets: | ||||||||||||||||||
Ameren | Derivative assets - commodity contracts(a): | |||||||||||||||||
Fuel oils | $ | 2 | $ | — | $ | 5 | $ | 7 | ||||||||||
Natural gas | — | 5 | — | 5 | ||||||||||||||
Power | — | 1 | 21 | 22 | ||||||||||||||
Total derivative assets - commodity contracts | $ | 2 | $ | 6 | $ | 26 | $ | 34 | ||||||||||
Nuclear decommissioning trust fund: | ||||||||||||||||||
Cash and cash equivalents | $ | 2 | $ | — | $ | — | $ | 2 | ||||||||||
Equity securities: | ||||||||||||||||||
U.S. large capitalization | 344 | — | — | 344 | ||||||||||||||
Debt securities: | ||||||||||||||||||
Corporate bonds | — | 57 | — | 57 | ||||||||||||||
Municipal bonds | — | 2 | — | 2 | ||||||||||||||
U.S. treasury and agency securities | — | 98 | — | 98 | ||||||||||||||
Asset-backed securities | — | 12 | — | 12 | ||||||||||||||
Other | — | 6 | — | 6 | ||||||||||||||
Total nuclear decommissioning trust fund | $ | 346 | $ | 175 | $ | — | $ | 521 | (b) | |||||||||
Total Ameren | $ | 348 | $ | 181 | $ | 26 | $ | 555 | ||||||||||
Ameren | Derivative assets - commodity contracts(a): | |||||||||||||||||
Missouri | Fuel oils | $ | 2 | $ | — | $ | 5 | $ | 7 | |||||||||
Natural gas | — | 1 | — | 1 | ||||||||||||||
Power | — | 1 | 21 | 22 | ||||||||||||||
Total derivative assets - commodity contracts | $ | 2 | $ | 2 | $ | 26 | $ | 30 | ||||||||||
Nuclear decommissioning trust fund: | ||||||||||||||||||
Cash and cash equivalents | $ | 2 | $ | — | $ | — | $ | 2 | ||||||||||
Equity securities: | ||||||||||||||||||
U.S. large capitalization | 344 | — | — | 344 | ||||||||||||||
Debt securities: | ||||||||||||||||||
Corporate bonds | — | 57 | — | 57 | ||||||||||||||
Municipal bonds | — | 2 | — | 2 | ||||||||||||||
U.S. treasury and agency securities | — | 98 | — | 98 | ||||||||||||||
Asset-backed securities | — | 12 | — | 12 | ||||||||||||||
Other | — | 6 | — | 6 | ||||||||||||||
Total nuclear decommissioning trust fund | $ | 346 | $ | 175 | $ | — | $ | 521 | (b) | |||||||||
Total Ameren Missouri | $ | 348 | $ | 177 | $ | 26 | $ | 551 | ||||||||||
Ameren | Derivative assets - commodity contracts(a): | |||||||||||||||||
Illinois | Natural gas | $ | — | $ | 4 | $ | — | $ | 4 | |||||||||
Liabilities: | ||||||||||||||||||
Ameren | Derivative liabilities - commodity contracts(a): | |||||||||||||||||
Fuel oils | $ | — | $ | — | $ | 3 | $ | 3 | ||||||||||
Natural gas | 2 | 28 | — | 30 | ||||||||||||||
Power | — | — | 109 | 109 | ||||||||||||||
Uranium | — | — | 7 | 7 | ||||||||||||||
Total Ameren | $ | 2 | $ | 28 | $ | 119 | $ | 149 | ||||||||||
Ameren | Derivative liabilities - commodity contracts(a): | |||||||||||||||||
Missouri | Fuel oils | $ | — | $ | — | $ | 3 | $ | 3 | |||||||||
Natural gas | 2 | 4 | — | 6 | ||||||||||||||
Power | — | — | 6 | 6 | ||||||||||||||
Uranium | — | — | 7 | 7 | ||||||||||||||
Total Ameren Missouri | $ | 2 | $ | 4 | $ | 16 | $ | 22 | ||||||||||
Ameren | Derivative liabilities - commodity contracts(a): | |||||||||||||||||
Illinois | Natural gas | $ | — | $ | 24 | $ | — | $ | 24 | |||||||||
Power | — | — | 103 | 103 | ||||||||||||||
Total Ameren Illinois | $ | — | $ | 24 | $ | 103 | $ | 127 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
(b) | Balance excludes $2 million of receivables, payables, and accrued income, net. |
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Other Unobservable Inputs (Level 3) | Total | ||||||||||||||
Assets: | |||||||||||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | 1 | $ | — | $ | 8 | $ | 9 | |||||||||
Natural gas | — | 2 | — | 2 | |||||||||||||
Power | — | 2 | 21 | 23 | |||||||||||||
Total derivative assets - commodity contracts | $ | 1 | $ | 4 | $ | 29 | $ | 34 | |||||||||
Nuclear decommissioning trust fund: | |||||||||||||||||
Cash and cash equivalents | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||
Equity securities: | |||||||||||||||||
U.S. large capitalization | 332 | — | — | 332 | |||||||||||||
Debt securities: | |||||||||||||||||
Corporate bonds | — | 52 | — | 52 | |||||||||||||
Municipal bonds | — | 2 | — | 2 | |||||||||||||
U.S. treasury and agency securities | — | 94 | — | 94 | |||||||||||||
Asset-backed securities | — | 10 | — | 10 | |||||||||||||
Other | — | 1 | — | 1 | |||||||||||||
Total nuclear decommissioning trust fund | $ | 335 | $ | 159 | $ | — | $ | 494 | |||||||||
Total Ameren | $ | 336 | $ | 163 | $ | 29 | $ | 528 | |||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Missouri | Fuel oils | $ | 1 | $ | — | $ | 8 | $ | 9 | ||||||||
Natural gas | — | 1 | — | 1 | |||||||||||||
Power | — | 2 | 21 | 23 | |||||||||||||
Total derivative assets - commodity contracts | $ | 1 | $ | 3 | $ | 29 | $ | 33 | |||||||||
Nuclear decommissioning trust fund: | |||||||||||||||||
Cash and cash equivalents | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||
Equity securities: | |||||||||||||||||
U.S. large capitalization | 332 | — | — | 332 | |||||||||||||
Debt securities: | |||||||||||||||||
Corporate bonds | — | 52 | — | 52 | |||||||||||||
Municipal bonds | — | 2 | — | 2 | |||||||||||||
U.S. treasury and agency securities | — | 94 | — | 94 | |||||||||||||
Asset-backed securities | — | 10 | — | 10 | |||||||||||||
Other | — | 1 | — | 1 | |||||||||||||
Total nuclear decommissioning trust fund | $ | 335 | $ | 159 | $ | — | $ | 494 | |||||||||
Total Ameren Missouri | $ | 336 | $ | 162 | $ | 29 | $ | 527 | |||||||||
Ameren | Derivative assets - commodity contracts(a): | ||||||||||||||||
Illinois | Natural gas | $ | — | $ | 1 | $ | — | $ | 1 | ||||||||
Liabilities: | |||||||||||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Fuel oils | $ | — | $ | — | $ | 3 | $ | 3 | |||||||||
Natural gas | 3 | 54 | — | 57 | |||||||||||||
Power | — | 2 | 110 | 112 | |||||||||||||
Uranium | — | — | 6 | 6 | |||||||||||||
Total Ameren | $ | 3 | $ | 56 | $ | 119 | $ | 178 | |||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Missouri | Fuel oils | $ | — | $ | — | $ | 3 | $ | 3 | ||||||||
Natural gas | 3 | 8 | — | 11 | |||||||||||||
Power | — | 2 | 2 | 4 | |||||||||||||
Uranium | — | — | 6 | 6 | |||||||||||||
Total Ameren Missouri | $ | 3 | $ | 10 | $ | 11 | $ | 24 | |||||||||
Ameren | Derivative liabilities - commodity contracts(a): | ||||||||||||||||
Illinois | Natural gas | $ | — | $ | 46 | $ | — | $ | 46 | ||||||||
Power | — | — | 108 | 108 | |||||||||||||
Total Ameren Illinois | $ | — | $ | 46 | $ | 108 | $ | 154 |
(a) | The derivative asset and liability balances are presented net of counterparty credit considerations. |
Net derivative commodity contracts | |||||||||
Three Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at April 1, 2014 | $ | 1 | $ | (a) | $ | 1 | |||
Realized and unrealized gains (losses) included in regulatory assets/liabilities | 1 | (a) | 1 | ||||||
Ending balance at June 30, 2014 | $ | 2 | $ | (a) | $ | 2 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | 1 | $ | (a) | $ | 1 | |||
Natural gas: | |||||||||
Beginning balance at April 1, 2014 | $ | — | $ | — | $ | — | |||
Purchases | — | 1 | 1 | ||||||
Settlements | — | (1 | ) | (1 | ) | ||||
Ending balance at June 30, 2014 | $ | — | $ | — | $ | — | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | — | $ | — | $ | — | |||
Power: | |||||||||
Beginning balance at April 1, 2014 | $ | 10 | $ | (120 | ) | $ | (110 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (13 | ) | 16 | 3 | |||||
Purchases | 34 | — | 34 | ||||||
Settlements | (15 | ) | 1 | (14 | ) | ||||
Transfers out of Level 3 | (1 | ) | — | (1 | ) | ||||
Ending balance at June 30, 2014 | $ | 15 | $ | (103 | ) | $ | (88 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | (1 | ) | $ | 15 | $ | 14 | ||
Uranium: | |||||||||
Beginning balance at April 1, 2014 | $ | (5 | ) | $ | (a) | $ | (5 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (4 | ) | (a) | (4 | ) | ||||
Settlements | 2 | (a) | 2 | ||||||
Ending balance at June 30, 2014 | $ | (7 | ) | $ | (a) | $ | (7 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | (4 | ) | $ | (a) | $ | (4 | ) |
(a) | Not applicable. |
Net derivative commodity contracts | |||||||||
Three Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at April 1, 2013 | $ | 5 | $ | (a) | $ | 5 | |||
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Ending balance at June 30, 2013 | $ | 3 | $ | (a) | $ | 3 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) | |
Natural gas: | |||||||||
Beginning balance at April 1, 2013 | $ | — | $ | 2 | $ | 2 | |||
Purchases | (1 | ) | — | (1 | ) | ||||
Ending balance at June 30, 2013 | $ | (1 | ) | $ | 2 | $ | 1 | ||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | — | $ | (1 | ) | |
Power: | |||||||||
Beginning balance at April 1, 2013 | $ | 2 | $ | (81 | ) | $ | (79 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | 1 | 1 | 2 | ||||||
Purchases | 40 | — | 40 | ||||||
Settlements | (9 | ) | — | (9 | ) | ||||
Transfers out of Level 3 | 3 | — | 3 | ||||||
Ending balance at June 30, 2013 | $ | 37 | $ | (80 | ) | $ | (43 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | 3 | $ | (4 | ) | $ | (1 | ) | |
Uranium: | |||||||||
Beginning balance at April 1, 2013 | $ | (2 | ) | $ | (a) | $ | (2 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Settlements | 1 | (a) | 1 | ||||||
Ending balance at June 30, 2013 | $ | (3 | ) | $ | (a) | $ | (3 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) |
(a) | Not applicable. |
Net derivative commodity contracts | |||||||||
Six Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at January 1, 2014 | $ | 5 | $ | (a) | $ | 5 | |||
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (1 | ) | (a) | (1 | ) | ||||
Settlements | (2 | ) | (a) | (2 | ) | ||||
Ending balance at June 30, 2014 | $ | 2 | $ | (a) | $ | 2 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | — | $ | (a) | $ | — | |||
Natural gas: | |||||||||
Beginning balance at January 1, 2014 | $ | — | $ | — | $ | — | |||
Purchases | — | (1 | ) | (1 | ) | ||||
Settlements | — | 1 | 1 | ||||||
Ending balance at June 30, 2014 | $ | — | $ | — | $ | — | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | — | $ | — | $ | — | |||
Power: | |||||||||
Beginning balance at January 1, 2014 | $ | 19 | $ | (108 | ) | $ | (89 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (18 | ) | 4 | (14 | ) | ||||
Purchases | 34 | — | 34 | ||||||
Settlements | (20 | ) | 1 | (19 | ) | ||||
Ending balance at June 30, 2014 | $ | 15 | $ | (103 | ) | $ | (88 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | (3 | ) | $ | 1 | $ | (2 | ) | |
Uranium: | |||||||||
Beginning balance at January 1, 2014 | $ | (6 | ) | $ | (a) | $ | (6 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (4 | ) | (a) | (4 | ) | ||||
Settlements | 3 | (a) | 3 | ||||||
Ending balance at June 30, 2014 | $ | (7 | ) | $ | (a) | $ | (7 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2014 | $ | (4 | ) | $ | (a) | $ | (4 | ) |
(a) | Not applicable. |
Net derivative commodity contracts | |||||||||
Six Months | Ameren Missouri | Ameren Illinois | Ameren | ||||||
Fuel oils: | |||||||||
Beginning balance at January 1, 2013 | $ | 5 | $ | (a) | $ | 5 | |||
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Purchases | 1 | (a) | 1 | ||||||
Settlements | (1 | ) | (a) | (1 | ) | ||||
Ending balance at June 30, 2013 | $ | 3 | $ | (a) | $ | 3 | |||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) | |
Natural gas: | |||||||||
Beginning balance at January 1, 2013 | $ | — | $ | — | $ | — | |||
Realized and unrealized gains (losses) included in regulatory assets/liabilities | — | 1 | 1 | ||||||
Purchases | (1 | ) | 1 | — | |||||
Ending balance at June 30, 2013 | $ | (1 | ) | $ | 2 | $ | 1 | ||
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | — | $ | — | $ | — | |||
Power: | |||||||||
Beginning balance at January 1, 2013 | $ | 11 | $ | (111 | ) | $ | (100 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | 6 | 15 | 21 | ||||||
Purchases | 40 | — | 40 | ||||||
Settlements | (22 | ) | 16 | (6 | ) | ||||
Transfers into Level 3 | (2 | ) | — | (2 | ) | ||||
Transfers out of Level 3 | 4 | — | 4 | ||||||
Ending balance at June 30, 2013 | $ | 37 | $ | (80 | ) | $ | (43 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | — | $ | 15 | $ | 15 | |||
Uranium: | |||||||||
Beginning balance at January 1, 2013 | $ | (2 | ) | $ | (a) | $ | (2 | ) | |
Realized and unrealized gains (losses) included in regulatory assets/liabilities | (2 | ) | (a) | (2 | ) | ||||
Settlements | 1 | (a) | 1 | ||||||
Ending balance at June 30, 2013 | $ | (3 | ) | $ | (a) | $ | (3 | ) | |
Change in unrealized gains (losses) related to assets/liabilities held at June 30, 2013 | $ | (1 | ) | $ | (a) | $ | (1 | ) |
(a) | Not applicable. |
2014 | 2013 | |||||||||||||||||
Ameren Missouri | Ameren Illinois | Ameren | Ameren Missouri | Ameren Illinois | Ameren | |||||||||||||
Three Months | ||||||||||||||||||
Transfers out of Level 3 / Transfers into Level 2 - Power | $ | (1 | ) | $ | — | $ | (1 | ) | $ | 3 | $ | — | $ | 3 | ||||
Six Months | ||||||||||||||||||
Transfers into Level 3 / Transfers out of Level 2 - Power | $ | — | $ | — | $ | — | $ | (2 | ) | $ | — | $ | (2 | ) | ||||
Transfers out of Level 3 / Transfers into Level 2 - Power | — | — | — | 4 | — | 4 | ||||||||||||
Net fair value of Level 3 transfers | $ | — | $ | — | $ | — | $ | 2 | $ | — | $ | 2 |
June 30, 2014 | December 31, 2013 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Ameren:(a) | |||||||||||||||
Long-term debt and capital lease obligations (including current portion) | $ | 5,944 | $ | 6,648 | $ | 6,038 | $ | 6,584 | |||||||
Preferred stock | 142 | 120 | 142 | 118 | |||||||||||
Ameren Missouri: | |||||||||||||||
Long-term debt and capital lease obligations (including current portion) | $ | 4,004 | $ | 4,464 | $ | 3,757 | $ | 4,124 | |||||||
Preferred stock | 80 | 72 | 80 | 71 | |||||||||||
Ameren Illinois: | |||||||||||||||
Long-term debt | $ | 1,940 | $ | 2,184 | $ | 1,856 | $ | 2,028 | |||||||
Preferred stock | 62 | 48 | 62 | 47 |
(a) | Preferred stock is recorded in “Noncontrolling Interests” on the consolidated balance sheet. |
Three Months | Six Months | ||||||||||||||
Agreement | Income Statement Line Item | Ameren Missouri | Ameren Illinois | Ameren Missouri | Ameren Illinois | ||||||||||
Ameren Missouri power supply | Operating Revenues | 2014 | $ | 3 | $ | (a) | $ | 3 | $ | (a) | |||||
agreements with Ameren Illinois | 2013 | (b) | (a) | 1 | (a) | ||||||||||
Ameren Missouri and Ameren Illinois | Operating Revenues | 2014 | 4 | 1 | 9 | 1 | |||||||||
rent and facility services | 2013 | 5 | (b) | 11 | 1 | ||||||||||
Ameren Missouri and Ameren Illinois | Operating Revenues | 2014 | 1 | (b) | 1 | (b) | |||||||||
miscellaneous support services | 2013 | (b) | 2 | (b) | 2 | ||||||||||
Total Operating Revenues | 2014 | $ | 8 | $ | 1 | $ | 13 | $ | 1 | ||||||
2013 | 5 | 2 | 12 | 3 | |||||||||||
Ameren Illinois power supply | Purchased Power | 2014 | $ | (a) | $ | 3 | $ | (a) | $ | 3 | |||||
agreements with Ameren Missouri | 2013 | (a) | (b) | (a) | 1 | ||||||||||
Ameren Illinois transmission | Purchased Power | 2014 | (a) | (b) | (a) | 1 | |||||||||
services with ATXI | 2013 | (a) | (b) | (a) | 1 | ||||||||||
Total Purchased Power | 2014 | $ | (a) | $ | 3 | $ | (a) | $ | 4 | ||||||
2013 | (a) | (b) | (a) | 2 | |||||||||||
Ameren Services support services | Other Operations and Maintenance | 2014 | $ | 32 | $ | 27 | $ | 65 | $ | 54 | |||||
agreement | 2013 | 28 | 24 | 60 | 48 | ||||||||||
Insurance premiums(c) | Other Operations and Maintenance | 2014 | (b) | (a) | (b) | (a) | |||||||||
2013 | (b) | (a) | (b) | (a) | |||||||||||
Total Other Operations and | 2014 | $ | 32 | $ | 27 | $ | 65 | $ | 54 | ||||||
Maintenance Expenses | 2013 | 28 | 24 | 60 | 48 | ||||||||||
Money pool borrowings (advances) | Interest Charges | 2014 | $ | (b) | $ | (b) | $ | (b) | $ | (b) | |||||
2013 | — | (b) | (b) | (b) |
(a) | Not applicable. |
(b) | Amount less than $1 million. |
(c) | Represents insurance premiums paid to Missouri Energy Risk Assurance Company LLC, an affiliate, for replacement power, property damage, and terrorism coverage. |
Type and Source of Coverage | Maximum Coverages | Maximum Assessments for Single Incidents | ||||||
Public liability and nuclear worker liability: | ||||||||
American Nuclear Insurers | $ | 375 | $ | — | ||||
Pool participation | 13,241 | (a) | 128 | (b) | ||||
$ | 13,616 | (c) | $ | 128 | ||||
Property damage: | ||||||||
NEIL | $ | 2,250 | (d) | $ | 23 | (e) | ||
European Mutual Association for Nuclear Insurance | 500 | (f) | — | |||||
$ | 2,750 | $ | 23 | |||||
Replacement power: | ||||||||
NEIL | $ | 490 | (g) | $ | 9 | (e) | ||
Missouri Energy Risk Assurance Company LLC | 64 | (h) | — |
(a) | Provided through mandatory participation in an industrywide retrospective premium assessment program. |
(b) | Retrospective premium under the Price-Anderson Act. This is subject to retrospective assessment with respect to a covered loss in excess of $375 million in the event of an incident at any licensed United States commercial reactor, payable at $19 million per year. |
(c) | Limit of liability for each incident under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. A company could be assessed up to $128 million per incident for each licensed reactor it operates with a maximum of $19 million per incident to be paid in a calendar year for each reactor. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors. |
(d) | NEIL provides $2.25 billion in property damage, decontamination, and premature decommissioning insurance. |
(e) | All NEIL insured plants could be subject to assessments should losses exceed the accumulated funds from NEIL. |
(f) | European Mutual Association for Nuclear Insurance provides $500 million in excess of the $2.25 billion property coverage provided by NEIL. |
(g) | Provides replacement power cost insurance in the event of a prolonged accidental outage. Weekly indemnity up to $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus up to $3.6 million per week for a minimum of 71 weeks thereafter for a total not exceeding the policy limit of $490 million. Nonradiation events are sub-limited to $327.6 million. |
(h) | Provides replacement power cost insurance in the event of a prolonged accidental outage. The coverage commences after the first 52 weeks of insurance coverage from NEIL concludes and is a weekly indemnity of up to $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Missouri Energy Risk Assurance Company LLC is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 8 - Related Party Transactions for more information on this affiliate transaction. |
Estimate | Recorded Liability(a) | ||||||||||
Low | High | ||||||||||
Ameren | $ | 259 | $ | 318 | $ | 259 | |||||
Ameren Missouri | 1 | 2 | 1 | ||||||||
Ameren Illinois | 258 | 316 | 258 |
(a) | Recorded liability represents the estimated minimum probable obligations, as no other amount within the range was a better estimate. |
Ameren | Ameren Missouri | Ameren Illinois | Total(a) | |||
1 | 49 | 59 | 73 |
(a) | Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants. |
Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||||||||
Three Months | Six Months | Three Months | Six Months | |||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Service cost | $ | 19 | $ | 22 | $ | 40 | $ | 46 | $ | 4 | $ | 5 | $ | 9 | $ | 11 | ||||||||||||||||
Interest cost | 42 | 41 | 91 | 81 | 12 | 11 | 25 | 23 | ||||||||||||||||||||||||
Expected return on plan assets | (57 | ) | (54 | ) | (114 | ) | (108 | ) | (16 | ) | (15 | ) | (32 | ) | (31 | ) | ||||||||||||||||
Amortization of: | ||||||||||||||||||||||||||||||||
Prior service cost (benefit) | — | (1 | ) | — | (2 | ) | (1 | ) | (1 | ) | (2 | ) | (2 | ) | ||||||||||||||||||
Actuarial loss (gain) | 12 | 24 | 24 | 46 | (2 | ) | 2 | (3 | ) | 4 | ||||||||||||||||||||||
Net periodic benefit cost (benefit) | $ | 16 | $ | 32 | (a) | $ | 41 | $ | 63 | (a) | $ | (3 | ) | $ | 2 | (a) | $ | (3 | ) | $ | 5 | (a) |
(a) | The net periodic benefit cost includes $3 million and $6 million in total net costs for pension benefits, for the three and six months ended June 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income (loss). The net periodic benefit cost includes $1 million and $- million in total net costs for postretirement benefits, for the three and six months ended June 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income (loss). |
Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||||||||
Three Months | Six Months | Three Months | Six Months | |||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||
Ameren Missouri | $ | 8 | $ | 18 | $ | 25 | $ | 36 | $ | 1 | $ | 2 | $ | 2 | $ | 5 | ||||||||||||||||
Ameren Illinois | 7 | 11 | 15 | 21 | (3 | ) | (1 | ) | (4 | ) | — | |||||||||||||||||||||
Other | 1 | 3 | (b) | 1 | 6 | (b) | (1 | ) | 1 | (b) | (1 | ) | — | (b) | ||||||||||||||||||
Ameren(a) | $ | 16 | $ | 32 | $ | 41 | $ | 63 | $ | (3 | ) | $ | 2 | $ | (3 | ) | $ | 5 |
(a) | Includes amounts for Ameren registrants and nonregistrant subsidiaries. |
(b) | The net periodic benefit cost includes $3 million and $6 million in total net costs for pension benefits, for the three and six months ended June 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income (loss). The net periodic benefit cost includes $1 million and $- million in total net costs for postretirement benefits, for the three and six months ended June 30, 2013, respectively, which were included in “Loss from discontinued operations, net of taxes” on Ameren’s consolidated statement of income (loss). |
Three Months | Six Months | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Operating revenues | $ | — | $ | 303 | $ | 1 | $ | 567 | ||||||||
Operating expenses | (1 | ) | (310 | ) | (3 | ) | (725 | ) | (a) | |||||||
Operating loss | (1 | ) | (7 | ) | (2 | ) | (158 | ) | ||||||||
Other income (loss) | — | 1 | — | (1 | ) | |||||||||||
Interest charges | — | (11 | ) | — | (22 | ) | ||||||||||
Loss before income taxes | (1 | ) | (17 | ) | (2 | ) | (181 | ) | ||||||||
Income tax (expense) benefit | — | 7 | — | (28 | ) | |||||||||||
Loss from discontinued operations, net of taxes | $ | (1 | ) | $ | (10 | ) | $ | (2 | ) | $ | (209 | ) |
(a) | Included a noncash pretax asset impairment charge of $168 million for the six months ended June 30, 2013, to reduce the carrying value of the New AER disposal group to its estimated fair value less cost to sell. |
June 30, 2014 | December 31, 2013 | ||||||
Assets of discontinued operations | |||||||
Cash and cash equivalents | $ | — | $ | — | |||
Accounts receivable and unbilled revenue | — | 5 | |||||
Materials and supplies | — | 5 | |||||
Property and plant, net | — | 142 | |||||
Accumulated deferred income taxes, net(a) | 15 | 13 | |||||
Total assets of discontinued operations | $ | 15 | $ | 165 | |||
Liabilities of discontinued operations | |||||||
Accounts payable and other current obligations | $ | 1 | $ | 5 | |||
Asset retirement obligations(b) | 32 | 40 | |||||
Total liabilities of discontinued operations | $ | 33 | $ | 45 |
(a) | Includes income tax assets related to the abandoned Meredosia and Hutsonville energy centers. |
(b) | Includes AROs associated with the abandoned Meredosia and Hutsonville energy centers of $32 million and $31 million, respectively, at June 30, 2014, and December 31, |
• | $138 million related to guarantees supporting Marketing Company for physically and financially settled power transactions with its counterparties that were in place at the December 2, 2013 closing of the divestiture, as well as for Marketing Company's clearing broker and other service agreements. If Marketing Company did not fulfill its obligations to these counterparties who had active open positions as of June 30, 2014, Ameren would have been required under its guarantees to provide approximately $10 million to the counterparties. |
• | $9 million related to requirements for lease agreements and potential environmental obligations. If New AER had not fulfilled its lease obligation as of June 30, 2014, Ameren would have been required to provide approximately $8 million to the leasing counterparty. |
Three Months | Ameren Missouri | Ameren Illinois | Other | Intersegment Eliminations | Ameren | |||||||||||||||
2014 | ||||||||||||||||||||
External revenues | $ | 893 | $ | 518 | $ | 8 | $ | — | $ | 1,419 | ||||||||||
Intersegment revenues | 7 | 1 | — | (8 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 126 | 28 | (4 | ) | — | 150 | ||||||||||||||
2013 | ||||||||||||||||||||
External revenues | $ | 883 | $ | 514 | $ | 6 | $ | — | $ | 1,403 | ||||||||||
Intersegment revenues | 6 | 2 | — | (8 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 84 | 31 | (10 | ) | — | 105 | ||||||||||||||
Six Months | ||||||||||||||||||||
2014 | ||||||||||||||||||||
External revenues | $ | 1,704 | $ | 1,292 | $ | 17 | $ | — | $ | 3,013 | ||||||||||
Intersegment revenues | 13 | 1 | 1 | (15 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 173 | 81 | (7 | ) | — | 247 | ||||||||||||||
2013 | ||||||||||||||||||||
External revenues | $ | 1,672 | $ | 1,197 | $ | 9 | $ | — | $ | 2,878 | ||||||||||
Intersegment revenues | 13 | 3 | 1 | (17 | ) | — | ||||||||||||||
Net income (loss) attributable to Ameren Corporation from continuing operations | 124 | 62 | (27 | ) | — | 159 | ||||||||||||||
As of June 30, 2014: | ||||||||||||||||||||
Total assets | $ | 13,203 | $ | 7,719 | $ | 773 | $ | (122 | ) | $ | 21,573 | (a) | ||||||||
As of December 31, 2013: | ||||||||||||||||||||
Total assets | $ | 12,904 | $ | 7,454 | $ | 752 | $ | (233 | ) | $ | 20,877 | (a) |
• | Union Electric Company, doing business as Ameren Missouri, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. |
• | Ameren Illinois Company, doing business as Ameren Illinois, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. |
Three Months | Six Months | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Net income (loss) attributable to Ameren Corporation | $ | 149 | $ | 95 | $ | 245 | $ | (50 | ) | |||||||
Earnings (loss) per common share - basic | 0.61 | 0.39 | 1.01 | (0.21 | ) | |||||||||||
Net income attributable to Ameren Corporation - continuing operations | 150 | 105 | 247 | 159 | ||||||||||||
Earnings per common share - basic - continuing operations | 0.62 | 0.44 | 1.02 | 0.66 |
• | increased electric and natural gas demand resulting from colder winter temperatures primarily in the first quarter and warmer early summer temperatures in the second quarter |
• | the absence in 2014 of costs associated with the Callaway energy center's 2013 refueling and maintenance outage. The next Callaway energy center refueling and maintenance outage is scheduled for the fourth quarter of 2014 (8 cents per share and 9 cents per share, respectively); |
• | the absence in 2014 of a reduction in 2013 revenues at Ameren Missouri resulting from the FAC prudence review charge for the estimated obligation to refund to customers amounts associated with sales recognized for the period from October 1, 2009, to May 31, 2011 (6 cents per share in both periods); |
• | decreased interest expense, primarily due to long-term debt redemptions and maturities at Ameren Missouri, Ameren Illinois and Ameren (parent) (2 cents per share and 5 cents per share, respectively); |
• | higher electric transmission rates at Ameren Illinois and ATXI because of additional rate base (1 cent per share and 4 cents per share, respectively); |
• | higher natural gas rates at Ameren Illinois pursuant to a December 2013 order (1 cent per share and 4 cents per share, respectively); and |
• | decreased other operations and maintenance expenses at Ameren (parent) and nonregistrant subsidiaries, primarily resulting from the substantial elimination of costs previously incurred in support of the divested merchant generation business (1 cent per share and 3 cents per share, respectively). |
• | a decrease in Ameren Illinois’ electric delivery service earnings for the second quarter of 2014, compared with the same period in 2013, due to timing of revenue recognition during the year under formula ratemaking that more than offset favorable effects resulting from increased rate base and a higher allowed return on equity as a result of increased yields on 30-year United States Treasury bonds (estimated at 1 cent per share); |
• | the reduction in revenue recorded at Ameren Illinois for an estimated electric transmission rate refund related to a case at FERC (1 cent per share in both periods); and |
• | an increase in the effective tax rate (1 cent per share in both periods). |
Ameren Missouri | Ameren Illinois | Other / Intersegment Eliminations | Ameren | ||||||||||||
Three Months 2014: | |||||||||||||||
Electric margins | $ | 645 | $ | 278 | $ | 3 | $ | 926 | |||||||
Natural gas margins | 17 | 88 | — | 105 | |||||||||||
Other revenues | 1 | — | (1 | ) | — | ||||||||||
Other operations and maintenance | (222 | ) | (195 | ) | 5 | (412 | ) | ||||||||
Depreciation and amortization | (117 | ) | (64 | ) | (2 | ) | (183 | ) | |||||||
Taxes other than income taxes | (81 | ) | (32 | ) | (1 | ) | (114 | ) | |||||||
Other income (expenses) | 14 | 4 | (1 | ) | 17 | ||||||||||
Interest charges | (54 | ) | (29 | ) | (6 | ) | (89 | ) | |||||||
Income taxes | (76 | ) | (21 | ) | (2 | ) | (99 | ) | |||||||
Income (loss) from continuing operations | 127 | 29 | (5 | ) | 151 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (1 | ) | (1 | ) | |||||||||
Net income (loss) | 127 | 29 | (6 | ) | 150 | ||||||||||
Preferred dividends | (1 | ) | (1 | ) | 1 | (1 | ) | ||||||||
Net income (loss) attributable to Ameren Corporation | $ | 126 | $ | 28 | $ | (5 | ) | $ | 149 | ||||||
Three Months 2013: | |||||||||||||||
Electric margins | $ | 606 | $ | 288 | $ | — | $ | 894 | |||||||
Natural gas margins | 18 | 85 | — | 103 | |||||||||||
Other revenues | — | 2 | (2 | ) | — | ||||||||||
Other operations and maintenance | (253 | ) | (196 | ) | 2 | (447 | ) | ||||||||
Depreciation and amortization | (113 | ) | (62 | ) | (3 | ) | (178 | ) | |||||||
Taxes other than income taxes | (79 | ) | (30 | ) | (2 | ) | (111 | ) | |||||||
Other income (expenses) | 11 | 1 | (1 | ) | 11 | ||||||||||
Interest charges | (56 | ) | (34 | ) | (10 | ) | (100 | ) | |||||||
Income (taxes) benefit | (49 | ) | (22 | ) | 5 | (66 | ) | ||||||||
Income (loss) from continuing operations | 85 | 32 | (11 | ) | 106 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (10 | ) | (10 | ) | |||||||||
Net income (loss) | 85 | 32 | (21 | ) | 96 | ||||||||||
Noncontrolling interests and preferred dividends | (1 | ) | (1 | ) | 1 | (1 | ) | ||||||||
Net income (loss) attributable to Ameren Corporation | $ | 84 | $ | 31 | $ | (20 | ) | $ | 95 | ||||||
Six Months 2014: | |||||||||||||||
Electric margins | $ | 1,157 | $ | 550 | $ | 9 | $ | 1,716 | |||||||
Natural gas margins | 45 | 245 | (1 | ) | 289 | ||||||||||
Other revenues | 1 | — | (1 | ) | — | ||||||||||
Other operations and maintenance | (449 | ) | (395 | ) | 12 | (832 | ) | ||||||||
Depreciation and amortization | (233 | ) | (127 | ) | (4 | ) | (364 | ) | |||||||
Taxes other than income taxes | (159 | ) | (78 | ) | (4 | ) | (241 | ) | |||||||
Other income and (expenses) | 24 | 3 | (1 | ) | 26 | ||||||||||
Interest charges | (106 | ) | (59 | ) | (16 | ) | (181 | ) | |||||||
Income (taxes) benefit | (105 | ) | (56 | ) | (2 | ) | (163 | ) | |||||||
Income (loss) from continuing operations | 175 | 83 | (8 | ) | 250 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (2 | ) | (2 | ) | |||||||||
Net income (loss) | 175 | 83 | (10 | ) | 248 | ||||||||||
Noncontrolling interests and preferred dividends | (2 | ) | (2 | ) | 1 | (3 | ) | ||||||||
Net income (loss) attributable to Ameren Corporation | $ | 173 | $ | 81 | $ | (9 | ) | $ | 245 | ||||||
Six Months 2013: | |||||||||||||||
Electric margins | $ | 1,099 | $ | 521 | $ | (2 | ) | $ | 1,618 | ||||||
Natural gas margins | 45 | 216 | (1 | ) | 260 | ||||||||||
Other revenues | — | 2 | (2 | ) | — | ||||||||||
Other operations and maintenance | (474 | ) | (372 | ) | — | (846 | ) | ||||||||
Depreciation and amortization | (224 | ) | (123 | ) | (6 | ) | (353 | ) | |||||||
Taxes other than income taxes | (156 | ) | (72 | ) | (5 | ) | (233 | ) | |||||||
Other income and (expenses) | 20 | (1 | ) | (1 | ) | 18 | |||||||||
Interest charges | (116 | ) | (65 | ) | (20 | ) | (201 | ) | |||||||
Income (taxes) benefit | (68 | ) | (42 | ) | 9 | (101 | ) | ||||||||
Income (loss) from continuing operations | 126 | 64 | (28 | ) | 162 | ||||||||||
Loss from discontinued operations, net of tax | — | — | (209 | ) | (209 | ) | |||||||||
Net income (loss) | 126 | 64 | (237 | ) | (47 | ) | |||||||||
Noncontrolling interests and preferred dividends | (2 | ) | (2 | ) | 1 | (3 | ) | ||||||||
Net income (loss) attributable to Ameren Corporation | $ | 124 | $ | 62 | $ | (236 | ) | $ | (50 | ) |
Three Months | Ameren Missouri | Ameren Illinois | Other(a) | Ameren | |||||||||||
Electric revenue change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | 11 | $ | 1 | $ | — | $ | 12 | |||||||
Base rates (estimate) | — | 1 | — | 1 | |||||||||||
Recovery of FAC under-recovery(c) | (9 | ) | — | — | (9 | ) | |||||||||
Off-system sales and transmission services revenues (included in base rates) | (20 | ) | — | — | (20 | ) | |||||||||
MEEIA (energy efficiency) | 9 | — | — | 9 | |||||||||||
Transmission services | — | 10 | 2 | 12 | |||||||||||
FAC prudence review charge in 2013 | 22 | — | — | 22 | |||||||||||
Bad debt, energy efficiency programs and environmental remediation cost riders | — | (3 | ) | — | (3 | ) | |||||||||
Illinois pass-through power supply costs | — | — | (2 | ) | (2 | ) | |||||||||
Reserve for potential transmission refund | — | (4 | ) | — | (4 | ) | |||||||||
Sales volume (excluding the estimated effect of abnormal weather) | (1 | ) | — | — | (1 | ) | |||||||||
Other | (1 | ) | (9 | ) | — | (10 | ) | ||||||||
Total electric revenue change | $ | 11 | $ | (4 | ) | $ | — | $ | 7 | ||||||
Fuel and purchased power change: | |||||||||||||||
Energy costs included in base rates and other | $ | 19 | $ | (6 | ) | $ | 1 | $ | 14 | ||||||
Recovery of FAC under-recovery(c) | 9 | — | — | 9 | |||||||||||
Illinois pass-through power supply costs | — | — | 2 | 2 | |||||||||||
Total fuel and purchased power change | $ | 28 | $ | (6 | ) | $ | 3 | $ | 25 | ||||||
Net change in electric margins | $ | 39 | $ | (10 | ) | $ | 3 | $ | 32 | ||||||
Natural gas margins change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | |||||
Base rates (estimate) | — | 5 | — | 5 | |||||||||||
Bad debt, energy efficiency programs and environmental remediation cost riders | — | (1 | ) | — | (1 | ) | |||||||||
Sales volume (excluding the estimated effect of abnormal weather) and other | (1 | ) | — | — | (1 | ) | |||||||||
Net change in natural gas margins | $ | (1 | ) | $ | 3 | $ | — | $ | 2 | ||||||
Six Months | Ameren Missouri | Ameren Illinois | Other(a) | Ameren | |||||||||||
Electric revenue change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | 37 | $ | 5 | $ | — | $ | 42 | |||||||
Base rates (estimate) | — | 23 | — | 23 | |||||||||||
Recovery of FAC under-recovery(c) | (13 | ) | — | — | (13 | ) | |||||||||
Off-system sales and transmission services revenues (included in base rates) | (27 | ) | — | — | (27 | ) | |||||||||
MEEIA (energy efficiency) | 20 | — | — | 20 | |||||||||||
Transmission services | — | 16 | 9 | 25 | |||||||||||
FAC prudence review charge in 2013 | 22 | — | — | 22 | |||||||||||
Bad debt, energy efficiency programs and environmental remediation cost riders | — | 3 | — | 3 | |||||||||||
Illinois pass-through power supply costs | — | (46 | ) | (2 | ) | (48 | ) | ||||||||
Reserve for potential transmission refund | — | (4 | ) | — | (4 | ) | |||||||||
Sales volume (excluding the estimated effect of abnormal weather) | (7 | ) | — | — | (7 | ) | |||||||||
Other | (4 | ) | (8 | ) | 1 | (11 | ) | ||||||||
Total electric revenue change | $ | 28 | $ | (11 | ) | $ | 8 | $ | 25 | ||||||
Fuel and purchased power change: | |||||||||||||||
Energy costs included in base rates and other | $ | 17 | $ | (6 | ) | $ | 1 | $ | 12 | ||||||
Recovery of FAC under-recovery(c) | 13 | — | — | 13 |
Illinois pass-through power supply costs | — | 46 | 2 | 48 | |||||||||||
Total fuel and purchased power change | $ | 30 | $ | 40 | $ | 3 | $ | 73 | |||||||
Net change in electric margins | $ | 58 | $ | 29 | $ | 11 | $ | 98 | |||||||
Natural gas margins change: | |||||||||||||||
Effect of weather (estimate)(b) | $ | 1 | $ | 5 | $ | — | $ | 6 | |||||||
Base rates (estimate) | — | 15 | — | 15 | |||||||||||
Gross receipts tax | — | 4 | — | 4 | |||||||||||
Bad debt, energy efficiency programs and environmental remediation cost riders | — | 2 | — | 2 | |||||||||||
Sales volume (excluding the estimated effect of abnormal weather) and other | (1 | ) | 3 | — | 2 | ||||||||||
Net change in natural gas margins | $ | — | $ | 29 | $ | — | $ | 29 |
(a) | Primarily includes amounts for ATXI and intercompany eliminations. |
(b) | Represents the estimated margin impact resulting primarily from the effects of changes in cooling and heating degree-days on electric and natural gas demand compared with the prior-year period; this is 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 energy costs recovered under the FAC through customer rates, with corresponding offsets to fuel expense due to amortization of a previously recorded regulatory asset. |
• | Early summer temperatures for the three months ended June 30, 2014, compared with the same period in 2013, |
• | The absence in 2014 of a reduction in revenues resulting from a July 2013 MoPSC prudence review order. Ameren Missouri recorded a FAC prudence review charge in 2013 for its estimated obligation to refund to its electric customers the earnings associated with sales recognized by Ameren Missouri from October 1, 2009, to May 31, 2011 ($22 million for both periods). |
• | Higher revenues associated with the MEEIA energy efficiency program cost recovery mechanism ($3 million and $7 million, respectively) and lost revenue recovery mechanism ($6 million and $13 million, respectively), which increased revenues by a combined $9 million and $20 million, respectively. The higher revenues were driven by greater customer participation in the second year of the MEEIA programs, which led to higher recovery of lost revenues. The lost revenue recovery mechanism helps compensate Ameren Missouri for lower sales from energy efficiency-related volume reductions in current and future periods. See Other Operations and Maintenance Expenses in this section for information on a related offsetting increase in energy efficiency program costs. |
• | Electric delivery service formula ratemaking adjustments resulting from the reconciliation of the revenue requirement |
• | Transmission revenues increased under forward-looking formula ratemaking because of increased rate base investment and higher recoverable costs ($10 million and $16 million, respectively). |
• | Early summer temperatures for the three months ended June 30, 2014, compared with the same period in 2013, were warmer, as cooling degree-days increased 20%. Winter temperatures for the six months ended June 30, 2014, compared with the same period in 2013, were colder, as heating degree-days increased 13%. Combined, the weather increased revenues by an estimated $1 million and $5 million, respectively. |
• | A net increase in recovery of bad debt charge-offs, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms, which increased revenues by $3 million, for the six months ended June 30, 2014, compared with the same period in 2013. See Other Operations and Maintenance Expenses in this section for information on a related offsetting net increase in energy efficiency and environmental remediation costs. |
• | Higher natural gas rates effective January 2014, which increased revenues by an estimated $5 million and $15 million, respectively. |
• | Winter temperatures in 2014 were colder compared to 2013 as heating degree-days increased 13% for the six months ended June 30, 2014, compared with the same period in 2013, which increased revenues by an estimated $5 million. |
• | Increased gross receipts taxes due primarily to higher natural gas rates and higher sales volumes as a result of colder winter temperatures in 2014, which increased revenues by $4 million for the six months ended June 30, 2014, compared with the same period in 2013. See Taxes Other Than Income Taxes in this section for information on a related offsetting increase to gross receipts taxes. |
• | An increase in transport sales volumes of 9%, primarily driven by higher demand from a few large industrial customers which increased revenues by $3 million for the |
• | A net increase in recovery of bad debt charge-offs, energy efficiency program costs and environmental remediation costs through rate-adjustment mechanisms which increased revenues by $2 million for the six months ended June 30, 2014, compared with the same period in 2013. See Other Operations and Maintenance Expenses in this section for information on a related offsetting net increase in energy efficiency and environmental remediation costs. |
• | A reduction in energy center maintenance costs ($37 million and $47 million, respectively), primarily due to the absence in 2014 of Callaway energy center refueling and maintenance costs incurred for the 2013 outage ($30 million and $36 million, respectively), and a reduction in maintenance costs at coal-fired energy centers ($7 million and $11 million, respectively). The next Callaway energy center refueling outage is scheduled for the fourth quarter of 2014. |
• | A decrease in storm-related costs, primarily due to fewer major storms in the second quarter of 2014 ($6 million in both periods). |
• | An increase in accrued disposal costs of low-level radioactive nuclear waste at the Callaway energy center ($8 million for the six months ended June 30, 2014, compared with the same period in 2013). |
• | An increase in energy efficiency program costs due to MEEIA requirements. These costs were offset by increased electric revenues from customer billings, with no overall effect on net income ($3 million and $7 million, respectively). |
• | An increase in labor costs, primarily because of wage increases ($2 million and $7 million, respectively). |
• | An increase in injury litigation expenses related to asbestos claims ($3 million and $4 million, respectively). |
• | An increase in bad debt expense due to a decreased rate of customer collections ($3 million and $2 million, respectively). |
• | An increase in electric distribution maintenance expenditures, primarily related to increased system repair and vegetation management work ($6 million and $8 million, respectively). |
• | An increase in labor costs, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals ($7 million for the six months ended June 30, 2014, compared with the same period in 2013). |
• | An increase in energy efficiency and environmental remediation costs. These costs were included in riders and therefore were offset by increased electric and natural gas revenues from customer billings, with no overall effect on net income ($6 million for the six months ended June 30, 2014, compared with the same period in 2013). |
• | An increase in injury litigation expenses related to asbestos claims ($2 million and $5 million, respectively). |
• | An increase in fees for outside services, primarily related to the IEIMA ($2 million and $3 million, respectively). |
• | A reduction in employee benefit costs, primarily due to lower pension and postretirement expenses caused by changes in actuarial assumptions and the performance of plan assets ($6 million and $7 million, respectively). |
• | A decrease in energy efficiency and environmental remediation costs. These costs were included in riders and therefore were offset by decreased electric and natural gas revenues from customer billings, with no overall effect on net income ($3 million for the second quarter of 2014, compared with the same period in 2013). |
• | A decrease in bad debt expense due to improved customer collections ($2 million and $4 million, respectively). |
Three Months | Six Months | ||||||||||
2014 | 2013 | 2014 | 2013 | ||||||||
Ameren(a) | 40 | % | 38 | % | 39 | % | 38 | % | |||
Ameren Missouri(a) | 37 | % | 37 | % | 38 | % | 35 | % | |||
Ameren Illinois(a) | 42 | % | 41 | % | 40 | % | 40 | % |
(a) | Based on the current estimate of the annual effective tax rate adjusted to reflect the tax effect of items discrete to the relevant period. |
Net Cash Provided By (Used In) Operating Activities | Net Cash Provided by (Used In) Investing Activities | Net Cash Provided by (Used In) Financing Activities | |||||||||||||||||||||||||||||||||
2014 | 2013 | Variance | 2014 | 2013 | Variance | 2014 | 2013 | Variance | |||||||||||||||||||||||||||
Ameren(a) - continuing operations | $ | 658 | $ | 729 | $ | (71 | ) | $ | (922 | ) | $ | (606 | ) | $ | (316 | ) | $ | 132 | $ | (165 | ) | $ | 297 | ||||||||||||
Ameren(a) - discontinued operations | (4 | ) | 39 | (43 | ) | 152 | (31 | ) | 183 | — | — | — | |||||||||||||||||||||||
Ameren Missouri | 212 | 338 | (126 | ) | (413 | ) | (285 | ) | (128 | ) | 228 | (182 | ) | 410 | |||||||||||||||||||||
Ameren Illinois | 301 | 426 | (125 | ) | (432 | ) | (279 | ) | (153 | ) | 132 | (49 | ) | 181 |
(a) | Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. |
• | A $70 million decrease in cash associated with Ameren Missouri’s under-recovered FAC costs. Deferrals and refunds exceeded recoveries in 2014 by $39 million, while recoveries exceeded deferrals in 2013 by $31 million. |
• | A $39 million decrease caused by changes in Ameren Missouri’s coal inventory levels due to 2013 delivery disruptions from flooding as well as increased costs. |
• | A $33 million decrease in the over-collection of natural gas commodity costs from customers under the PGAs, primarily related to Ameren Illinois. |
• | The 2014 refunds to Ameren Illinois customers of $31 million as required under the provisions of the IEIMA for the 2012 revenue requirement reconciliation adjustment, as compared with no such refunds in the first six months of 2013. |
• | A $26 million increase in rebate payments provided for customer-installed solar generation at Ameren Missouri. |
• | A $22 million increase in payments associated with stock-based compensation awards in accordance with the provisions of the 2006 Incentive Plan. |
• | A net $20 million decrease in returns of collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes at Ameren Illinois, partially offset by the |
• | An $18 million increase in expenditures for energy efficiency programs that will be recovered through future customer billings. |
• | A $16 million increase in the cost of natural gas held in storage at Ameren Illinois because of increased prices and timing of injections. |
• | The absence in 2014 of $14 million received in 2013 for storm restoration assistance provided to nonaffiliated utilities, primarily at Ameren Missouri. |
• | A $12 million increase in payments to contractors at Ameren Illinois for additional reliability, maintenance, and IEIMA projects. |
• | A $10 million increase in labor costs at Ameren Illinois, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals. |
• | An $8 million increase in property tax payments at Ameren Missouri caused by higher assessed property tax values and increased property tax rates. |
• | Electric and natural gas margins, as discussed in Results of Operations, increased by $82 million, excluding the noncash FAC prudence review charge in 2013 and the noncash IEIMA revenue requirement reconciliation adjustments for 2014 and 2013, as the collections from customers for those adjustments will occur in a subsequent year. |
• | Income tax refunds of $6 million in 2014, compared with income tax payments of $60 million in 2013. The change is attributable to increased payments at Ameren Missouri and |
• | A $36 million decrease in interest payments, primarily due to decreases at Ameren Missouri and Ameren Illinois discussed below. |
• | A $32 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers. |
• | A $23 million decrease in payments caused by the timing of the Callaway nuclear refueling and maintenance outages at Ameren Missouri. |
• | A $17 million decrease in pension and postretirement benefit plan contributions resulting from timing of payments, changes in actuarial assumptions, and the performance of plan assets. |
• | A $122 million increase in income tax payments resulting primarily from a 2014 payment related to a reduction in deductions for capitalized expenditures for the 2013 tax year. |
• | A $70 million decrease in cash associated with under-recovered FAC costs. Deferrals and refunds exceeded recoveries in 2014 by $39 million, while recoveries exceeded deferrals in 2013 by $31 million. |
• | A $39 million decrease caused by changes in coal inventory levels due to 2013 delivery disruptions from flooding as well as increased costs. |
• | A $26 million increase in rebate payments provided for customer-installed solar generation. |
• | A $13 million increase in expenditures for energy efficiency programs that will be recovered through future customer billings. |
• | The absence in 2014 of $10 million received in 2013 for storm restoration assistance provided to nonaffiliated utilities. |
• | An $8 million increase in property tax payments caused by higher assessed property tax values and increased property tax rates. |
• | A $7 million decrease in natural gas commodity over-recovered costs under the PGA. |
• | A $79 million increase in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers. |
• | Electric and natural gas margins, as discussed in Results of Operations, increased by $36 million, excluding the noncash FAC prudence review charge in 2013. |
• | A $23 million decrease in payments caused by the timing of the Callaway nuclear refueling and maintenance outages. |
• | A $20 million decrease in interest payments, primarily due to reductions in cost of borrowings associated with commercial paper issuances that replaced higher interest long-term debt instruments redeemed and retired in October 2013. |
• | A $5 million decrease in pension and postretirement benefit plan contributions resulting from changes in actuarial assumptions and the performance of plan assets. |
• | A $43 million decrease in accounts receivable balances to reflect the timing of revenues earned, but not yet collected, from customers. |
• | The 2014 refunds to customers of $31 million as required under the provisions of the IEIMA for the 2012 revenue requirement reconciliation adjustment, as compared with no such refunds in the first six months of 2013. |
• | A $26 million decrease in the over-collection of natural gas commodity costs from customers under the PGA. |
• | A net $17 million decrease in returns of collateral posted with counterparties primarily due to changes in the market prices of power and natural gas and in contracted commodity volumes, partially offset by the effect of credit rating upgrades. |
• | A $16 million increase in the cost of natural gas held in storage because of increased prices and timing of injections. |
• | A $12 million increase in payments to contractors for additional reliability, maintenance, and IEIMA projects. |
• | A $10 million increase in labor costs, primarily because of wage increases and staff additions to meet enhanced reliability and customer service goals. |
• | A $7 million decrease in income tax refunds resulting primarily from a reduction in accelerated depreciation deductions. |
• | A $5 million increase in expenditures for energy efficiency programs that will be recovered through customer billings over time. |
• | Electric and natural gas margins, as discussed in Results of Operations, increased by $35 million, excluding the effect of the noncash IEIMA revenue requirement reconciliation adjustments for 2014 and 2013, as the collections from customers for those adjustments will occur in a subsequent year. |
• | A $16 million decrease in interest payments, primarily due to long-term debt redemptions in January 2014. |
Expiration | Borrowing Capacity | Credit Available | |||||||
Ameren and Ameren Missouri: | |||||||||
2012 Missouri Credit Agreement | November 2017 | $ | 1,000 | $ | 1,000 | ||||
Ameren and Ameren Illinois: | |||||||||
2012 Illinois Credit Agreement | November 2017 | 1,100 | 1,100 | ||||||
Ameren: | |||||||||
Less: Commercial paper outstanding | (b) | (793 | ) | ||||||
Less: Letters of credit(a) | (b) | (13 | ) | ||||||
Total | $ | 2,100 | $ | 1,294 |
(a) | As of June 30, 2014, $9 million of the letters of credit relate to Ameren's credit support obligations to New AER. See Note 12 – Divestiture Transactions and Discontinued Operations under Part I, Item 1, of this report for additional information. |
(b) | Not applicable. |
Six Months | |||||||||
Month Issued, Redeemed or Matured | 2014 | 2013 | |||||||
Issuances | |||||||||
Long-term debt | |||||||||
Ameren Missouri: | |||||||||
3.50% Senior secured notes due 2024 | April | $ | 350 | $ | — | ||||
Ameren Illinois: | |||||||||
4.30% Senior secured notes due 2044 | June | 248 | — | ||||||
Total Ameren long-term debt issuances | $ | 598 | $ | — | |||||
Redemptions and Maturities | |||||||||
Long-term debt | |||||||||
Ameren (parent): | |||||||||
8.875% Senior unsecured notes due 2014 | May | 425 | — | ||||||
Ameren Missouri: | |||||||||
5.50% Senior secured notes due 2014 | May | 104 | — | ||||||
Ameren Illinois: | |||||||||
5.90% Series 1993 due 2023(a) | January | 32 | — | ||||||
5.70% 1994A Series due 2024(a) | January | 36 | — | ||||||
5.95% 1993 Series C-1 due 2026 | January | 35 | — | ||||||
5.70% 1993 Series C-2 due 2026 | January | 8 | — | ||||||
5.40% 1998A Series due 2028 | January | 19 | — | ||||||
5.40% 1998B Series due 2028 | January | 33 | — | ||||||
Total Ameren long-term debt redemptions and maturities | $ | 692 | $ | — |
SIx Months | |||||||
2014 | 2013 | ||||||
Ameren Missouri | $ | 155 | $ | 180 | |||
Ameren Illinois | — | 30 | |||||
Dividends paid by Ameren | 194 | 194 |
Moody’s | S&P | Fitch | ||||
Ameren: | ||||||
Issuer/corporate credit rating | Baa2 | BBB+ | BBB+ | |||
Senior unsecured debt | Baa2 | BBB | BBB+ | |||
Commercial paper | P-2 | A-2 | F2 | |||
Ameren Missouri: | ||||||
Issuer/corporate credit rating | Baa1 | BBB+ | BBB+ | |||
Secured debt | A2 | A | A | |||
Senior unsecured debt | Baa1 | BBB+ | A- | |||
Commercial paper | P-2 | A-2 | F2 | |||
Ameren Illinois: | ||||||
Issuer/corporate credit rating | Baa1 | BBB+ | BBB | |||
Secured debt | A2 | A | A- | |||
Senior unsecured debt | Baa1 | BBB+ | BBB+ | |||
Commercial paper | P-2 | A-2 | F2 |
• | 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. |
• | Ameren continues to pursue its plans to invest in FERC-regulated electric transmission. MISO has approved three electric transmission projects to be developed by ATXI. The first project, Illinois Rivers, involves the construction of a 345-kilovolt line from western Indiana across the state of Illinois to eastern Missouri. ATXI obtained a certificate of public convenience and necessity and project approval from the ICC for the Illinois Rivers project. A full range of construction activities is scheduled in 2014. The first sections of the Illinois Rivers project are expected to be completed in 2016. The last section of this project is expected to be completed by 2019. The Spoon River project in northwest Illinois and the Mark Twain project in northeast Missouri are the other two projects approved by MISO. These two projects are expected to be completed in 2018. ATXI plans to request a certificate of public convenience and necessity and project approval from the ICC for the Spoon River project in the third quarter of 2014. An ICC decision on this filing is expected in 2015. The total investment in these three projects is expected to be $1.4 billion through 2019. In early 2015, ATXI expects to update the estimated cost of the Illinois Rivers project incorporating the final route approved by the ICC, which is longer than originally proposed. Separate from the ATXI projects discussed above, Ameren Illinois expects to invest approximately $850 million in electric transmission assets through 2018 to address load growth and reliability requirements. |
• | In July 2013, Illinois enacted the Natural Gas Consumer, Safety and Reliability Act, which encourages Illinois natural gas utilities to accelerate modernization of the state's natural gas infrastructure and provides additional ICC oversight of natural gas utility performance. The law allows natural gas utilities the option to file for, and requires the ICC to approve, a rate rider mechanism to recover costs of certain natural gas infrastructure investments made between rate cases. The law does not require a minimum level of investment. Ameren Illinois expects to begin including investments under this regulatory framework in 2015. Ameren Illinois' decision to accelerate modernization of its natural gas infrastructure under this regulatory framework is dependent upon multiple considerations, including the allowed return on equity under this framework compared with other Ameren and Ameren Illinois investment options. |
• | 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 customer billings for that year. Consequently, Ameren Illinois' 2014 electric delivery service revenues will be based on its 2014 actual recoverable costs, rate base, and return on common equity as calculated under the IEIMA's performance-based formula ratemaking |
• | In December 2013, the ICC issued an order with respect to Ameren Illinois' annual update IEIMA filing. The ICC approved a net $45 million decrease in Ameren Illinois' electric delivery service rates, which represents an annual revenue requirement increase of $23 million primarily due to higher recoverable costs in 2012 compared to 2011, offset by a $68 million refund to customers relating to the 2012 revenue requirement reconciliation. The ICC decision issued in December 2013 established new rates that became effective January 1, 2014. These rates have affected, and will continue to affect, Ameren Illinois' cash receipts during 2014, but not its operating revenues, which will instead be determined by the IEIMA's 2014 revenue requirement reconciliation. The 2014 revenue requirement reconciliation will be reflected as a regulatory asset or liability that will be collected from or refunded to customers in 2016. |
• | In April 2014, Ameren Illinois filed with the ICC its annual electric delivery service formula rate update to establish the revenue requirement used to set rates for 2015. Pending ICC approval, Ameren Illinois’ update filing, as revised in July 2014, will result in a $205 million increase in Ameren Illinois’ electric delivery service revenue requirement beginning in January 2015. This update reflects an increase to the annual formula rate based on 2013 actual costs and expected net plant additions for 2014, an increase to include the annual reconciliation of the revenue requirement in effect for 2013 to the actual costs incurred in that year, and an increase resulting from the conclusion of a refund to customers in 2014 for the 2012 revenue requirement reconciliation. An ICC decision in this April 2014 filing is expected by December 2014 and will establish rates for 2015. These rates will affect Ameren Illinois' cash receipts during 2015. |
• | In December 2013, the ICC issued an order that authorized a $32 million increase in Ameren Illinois’ annual natural gas delivery service revenues. This request was based on a future test year of 2014, which improves the ability to earn returns allowed by regulators. The new rates became effective January 1, 2014. |
• | In February 2014, Ameren Missouri’s largest customer, Noranda, and 37 residential customers filed an earnings complaint case with the MoPSC. In the earnings complaint case, Noranda and the residential customers asserted that Ameren Missouri’s electric service business is earning more than the 9.8% return on common equity authorized in the MoPSC's December 2012 electric rate order. Noranda and the residential customers are currently requesting the MoPSC approve a $49 million reduction to Ameren Missouri’s annual revenue requirement. Included in Noranda’s request is a reduction of Ameren Missouri’s authorized return on common equity to 9.4%. The MoPSC staff has filed testimony in this case that recommends no reduction to Ameren Missouri’s annual revenue requirement. Ameren Missouri does not believe that a reduction in electric |
• | In July 2014, Ameren Missouri filed a request with the MoPSC seeking approval to increase its annual revenues for electric service by $264 million. The rate request seeks recovery of increased net energy costs and rebates provided for customer-installed solar generation, as well as recovery of and a return on additional electric infrastructure investments made for the benefit of Ameren Missouri’s customers. Plant additions to rate base since the last electric rate order are expected to total approximately $1.4 billion through the anticipated true-up date in this rate case and include electric infrastructure investments for upgrades to the electrostatic precipitators at the coal-fired Labadie energy center to meet more stringent environmental regulations, the replacement of the nuclear reactor vessel head at the Callaway energy center in order to ensure continued safe and dependable operations, two new substations in St. Louis, and the O’Fallon energy center, which will be Missouri’s largest investor-owned utility solar facility, among other additions. Approximately $127 million of the request relates to an increase in net energy costs above the current levels included in base rates previously authorized by the MoPSC in its December 2012 electric rate order, 95% of which, absent initiation of this general rate proceeding, would have been reflected in rate adjustments implemented under Ameren Missouri’s existing FAC. The electric rate increase request is based on a 10.4% return on equity, a capital structure composed of 51.6% common equity, an electric rate base for Ameren Missouri of $7.3 billion, and a test year ended March 31, 2014, with certain pro-forma adjustments expected through the anticipated true-up date of December 31, 2014. The MoPSC proceeding relating to the proposed electric service rate changes will take place over a period of up to 11 months and a decision by the MoPSC in such proceeding is expected by May 2015, with rates effective by June 2015. |
• | As we continue to experience cost increases and make infrastructure investments, Ameren Missouri and Ameren Illinois expect to seek regular electric and natural gas rate increases and timely cost recovery and tracking mechanisms from their regulators. Ameren Missouri and |
• | Ameren and Ameren Missouri also are pursuing recovery from an insurer, 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’s and Ameren Missouri’s results of operations, financial position, and liquidity could be adversely affected if Ameren Missouri’s remaining liability insurance claim of $41 million as of June 30, 2014, is not paid. |
• | Ameren Missouri's next scheduled refueling and maintenance outage at its Callaway energy center will be in the fall of 2014. During a scheduled outage, which occurs every 18 months, maintenance expenses increase relative to non-outage years. Additionally, depending on the availability of its other generation sources and the market prices for power, Ameren Missouri's purchased power costs may increase and the amount of excess power available for sale may decrease versus non-outage years. Changes in purchased power costs and excess power available for sale are included in the FAC, resulting in limited impacts to earnings. Additional maintenance costs incurred during the outage will not be fully recovered in 2014, because revenues relating to the additional maintenance costs are recovered over 18 months. Ameren Missouri expects to incur maintenance costs of $35 million to $40 million relating to the fall 2014 refueling and maintenance outage. |
• | Ameren Missouri continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. |
• | As of June 30, 2014, Ameren Missouri had capitalized $69 million of costs incurred to license additional nuclear generation at its Callaway energy site. If efforts are abandoned or management concludes it is probable the costs incurred will be disallowed in rates, a charge to earnings would be recognized in the period in which that determination is made. |
• | Environmental regulations, as well as future initiatives, including those related to greenhouse gas emissions, or other actions taken by the EPA, could result in significant increases in capital expenditures and operating costs. These expenses could be prohibitive at some of Ameren Missouri's coal-fired energy centers, particularly at its Meramec energy center. Ameren Missouri's capital expenditures are subject to MoPSC prudence reviews, |
• | Ameren Missouri continues to evaluate its potential compliance plans for the Clean Power Plan. Based on preliminary studies, if the proposed rules were to be made final, Ameren Missouri anticipates new or accelerated capital expenditures and increased fuel costs would be required to achieve compliance. As proposed, the Clean Power Plan would require the states, including Missouri and Illinois, to submit compliance plans as early as 2016. The states’ compliance plans may require Ameren Missouri to construct combined cycle and renewable energy centers, currently estimated to cost approximately $2 billion by 2020, that Ameren Missouri believes would otherwise not be necessary to meet the energy needs of its customers. Additionally, the proposed rule could result in the closure or alteration of the operation of some of its coal-fired energy centers. |
• | Both Ameren Illinois and ATXI have FERC authorization to employ a forward-looking rate calculation with an annual revenue requirement reconciliation for each company’s electric transmission business. With the projected rates that became effective on January 1, 2014, Ameren Illinois’ 2014 revenue requirement for its electric transmission business is expected to increase by $15 million over 2013 levels due to rate base growth. With the projected rates that became effective on January 1, 2014, ATXI’s 2014 revenue requirement for its electric transmission business is expected to increase by $21 million over 2013 levels due to rate base growth, primarily relating to the Illinois Rivers project. |
• | In November 2013, a customer group filed a complaint case with FERC seeking a reduction in the allowed return on common equity to 9.15%, as well as a limit on the common equity ratio, under the MISO tariff. Currently, the FERC-allowed return on common equity for MISO transmission owners is 12.38%. This complaint case could result in a reduction to Ameren Illinois' and ATXI's allowed return on common equity. That reduction could also result in a refund for transmission service revenues earned after the filing of the complaint case in November 2013. FERC has not issued an order in this case, and it is under no deadline to do so. In June 2014, FERC issued an order that reduced the base allowed return on common equity for New England transmission owners from 11.14% to 10.57% with rate incentives allowed up to 11.74%. If FERC lowered our allowed base return on equity to 10.57%, as established in the New England transmission owners’ case, with no additional rate incentives, the required refund for Ameren and Ameren Illinois would be $9 million and $7 million, respectively, from the filing of the complaint case in November 2013 through June 30, 2014. The estimated ongoing annual reduction in revenues if the MISO return on equity was 10.57% for Ameren and Ameren Illinois would be $16 million and $12 million, respectively. Ameren Missouri does not expect that a reduction of its allowed base return |
• | Cooling degree-days in Ameren’s service territories during July 2014 were 34% lower than normal July weather conditions and 16% lower than July 2013. This cooler weather will have an unfavorable impact on Ameren’s, Ameren Missouri’s and Ameren Illinois’ results of operations. |
• | For additional information regarding recent rate orders and related appeals, pending requests filed with state and federal regulatory commissions, and Taum Sauk matters, see Note 2 – Rate and Regulatory Matters, Note 9 – Commitments and Contingencies, and Note 10 – Callaway Energy Center under Part I, Item 1, of this report and Note 2 – Rate and Regulatory Matters under Part II, Item 8, of the Form 10-K. |
• | 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 liquidity, credit metrics, and related access to capital for Ameren's rate-regulated businesses. |
• | The use of cash from operating activities and short-term borrowings to fund capital expenditures and other long-term investments may periodically result in a working capital deficit, defined as current liabilities exceeding current assets, as was the case for Ameren and Ameren Illinois at June 30, 2014. The working capital deficit as of June 30, 2014, was primarily the result of Ameren’s decision to utilize commercial paper issuances, as opposed to long-term debt. With the 2012 Credit Agreements, Ameren has access to $2.1 billion of credit capacity of which $1.3 billion was available at June 30, 2014. The Ameren Companies expect a reduction in interest expense based on their refinancing activities in 2014. |
• | Ameren expects its cash used for capital expenditures and dividends to exceed cash provided by operating activities over the next few years. |
• | As of June 30, 2014, Ameren had $357 million in tax benefits from federal and state net operating loss carryforwards (Ameren Missouri – $35 million and Ameren Illinois – $83 million) and $110 million in federal and state income tax credit carryforwards (Ameren Missouri – $12 million and Ameren Illinois – none). Consistent with the tax allocation agreement between Ameren and its subsidiaries, these carryforwards are expected to partially offset income tax liabilities in 2014 for Ameren Missouri and for Ameren and Ameren Illinois into 2016. In addition, Ameren has $85 million of expected income tax refunds and state overpayments that will offset income tax liabilities into 2016. These tax benefits, primarily at the Ameren (parent) level, when realized, will be available to finance electric transmission investments, specifically ATXI's Illinois Rivers project. These tax benefits are projected to reduce or eliminate Ameren's need to issue additional equity to fund these investments over the next few years. |
• | In December 2011, the IRS issued new guidance on the treatment of amounts paid to acquire, produce, or improve tangible property and dispositions of such property with respect to electric transmission, distribution, and generation assets as well as natural gas transmission and distribution assets. Final regulations related to this guidance were issued in September 2013. Ameren expects to use $50 million (Ameren Missouri - $30 million and Ameren Illinois - $20 million) in federal income tax net operating loss carryforward benefits to offset tax liabilities related to the accounting method change that Ameren expects to file with the IRS in 2014 in connection with this new guidance. |
• | Ameren has entered into an agreement with a buyer to sell the Meredosia energy center in 2014, provided certain closing conditions are met, for $25 million and the assumption of certain liabilities. Any proceeds received or gain recognized in connection with a sale would be reflected in discontinued operations. |
• | The Ameren Companies have multiyear credit agreements that cumulatively provide $2.1 billion of credit through November 14, 2017. See Note 3 – Short-term Debt and Liquidity under Part I, Item 1, of this report for additional information regarding the 2012 Credit Agreements. Ameren, Ameren Missouri and Ameren Illinois believe that their liquidity is adequate given their expected cash from operating activities, 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. |
2014 | 2015 | 2016 - 2018 | ||||||
Ameren: | ||||||||
Coal | 100 | % | 100 | % | 65 | % | ||
Coal transportation | 100 | 100 | 80 | |||||
Nuclear fuel | 100 | 100 | 79 | |||||
Natural gas for generation | 38 | 15 | 3 | |||||
Natural gas for distribution(a) | 51 | 14 | 4 | |||||
Purchased power for Ameren Illinois(b) | 100 | 79 | 23 | |||||
Ameren Missouri: | ||||||||
Coal | 100 | % | 100 | % | 65 | % | ||
Coal transportation | 100 | 100 | 80 | |||||
Nuclear fuel | 100 | 100 | 79 | |||||
Natural gas for generation | 38 | 15 | 3 | |||||
Natural gas for distribution(a) | 50 | 25 | 14 | |||||
Ameren Illinois: | ||||||||
Natural gas for distribution(a) | 52 | % | 13 | % | 3 | % | ||
Purchased power(b) | 100 | 79 | 23 |
(a) | Represents the percentage of natural gas price hedged for peak winter season of November through March. The year 2014 represents November 2014 through March 2015. The year 2015 represents November 2015 through March 2016. This continues each successive year through March 2019. |
(b) | Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. |
Three Months Ended June 30, 2014 | Ameren Missouri | Ameren Illinois | Ameren | ||||||||
Fair value of contracts at beginning of period, net | $ | — | $ | (144 | ) | $ | (144 | ) | |||
Contracts realized or otherwise settled during the period | (9 | ) | 4 | (5 | ) | ||||||
Changes in fair values attributable to changes in valuation technique and assumptions | — | — | — | ||||||||
Fair value of new contracts entered into during the period | 19 | — | 19 | ||||||||
Other changes in fair value | (2 | ) | 17 | 15 | |||||||
Fair value of contracts outstanding at end of period, net | $ | 8 | $ | (123 | ) | $ | (115 | ) | |||
Six Months Ended June 30, 2014 | |||||||||||
Fair value of contracts at beginning of year, net | $ | 9 | $ | (153 | ) | $ | (144 | ) | |||
Contracts realized or otherwise settled during the period | (17 | ) | 19 | 2 | |||||||
Changes in fair values attributable to changes in valuation technique and assumptions | — | — | — | ||||||||
Fair value of new contracts entered into during the period | 19 | — | 19 | ||||||||
Other changes in fair value | (3 | ) | 11 | 8 | |||||||
Fair value of contracts outstanding at end of period, net | $ | 8 | $ | (123 | ) | $ | (115 | ) |
Sources of Fair Value | Maturity Less than 1 Year | Maturity 1-3 Years | Maturity 4-5 Years | Maturity in Excess of 5 Years | Total Fair Value | ||||||||||||||
Ameren Missouri: | |||||||||||||||||||
Level 1 | $ | (1 | ) | $ | 1 | $ | — | $ | — | $ | — | ||||||||
Level 2(a) | (1 | ) | (1 | ) | — | — | (2 | ) | |||||||||||
Level 3(b) | 13 | (3 | ) | — | — | 10 | |||||||||||||
Total | $ | 11 | $ | (3 | ) | $ | — | $ | — | $ | 8 | ||||||||
Ameren Illinois: | |||||||||||||||||||
Level 1 | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||
Level 2(a) | (13 | ) | (8 | ) | 1 | — | (20 | ) | |||||||||||
Level 3(b) | (7 | ) | (17 | ) | (16 | ) | (63 | ) | (103 | ) | |||||||||
Total | $ | (20 | ) | $ | (25 | ) | $ | (15 | ) | $ | (63 | ) | $ | (123 | ) | ||||
Ameren: | |||||||||||||||||||
Level 1 | $ | (1 | ) | $ | 1 | $ | — | $ | — | $ | — | ||||||||
Level 2(a) | (14 | ) | (9 | ) | 1 | — | (22 | ) | |||||||||||
Level 3(b) | 6 | (20 | ) | (16 | ) | (63 | ) | (93 | ) | ||||||||||
Total | $ | (9 | ) | $ | (28 | ) | $ | (15 | ) | $ | (63 | ) | $ | (115 | ) |
(a) | Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed-price vs. floating over-the-counter natural gas swaps. |
(b) | Principally power forward contract values based on information from external sources, historical results, and our estimates. Also includes option contract values based on a Black-Scholes model. |
(a) | Evaluation of Disclosure Controls and Procedures |
(b) | Changes in Internal Controls over Financial Reporting |
• | Ameren Missouri’s electric rate case filed with the MoPSC in July 2014; |
• | Ameren Illinois’ annual electric delivery service formula rate update filed with the ICC in April 2014; |
• | Ameren Illinois' appeals of the ICC's December 2013 electric rate order and natural gas rate order; |
• | FERC litigation to determine wholesale distribution revenues for five of Ameren Illinois' wholesale customers; |
• | complaint cases filed by Noranda and 37 residential customers with the MoPSC in February 2014 requesting a reduction to Ameren Missouri's electric rates, including a reduction to its allowed return on equity, and certain rate shift changes; |
• | Entergy's rehearing request of a FERC May 2012 order requiring Entergy to refund to Ameren Missouri additional charges paid under an expired power purchase agreement; |
• | Ameren Illinois' request for rehearing of FERC's June 2014 orders, the appeal filed with the United States Court of Appeals for the District of Columbia Circuit, and settlement procedures regarding a potential electric transmission rate refund; |
• | a complaint case filed with FERC by a customer group seeking a reduction in the allowed return on common equity, as well as a limit on the common equity ratio, under the MISO tariff; |
• | the EPA's Clean Air Act-related litigation against Ameren Missouri; |
• | remediation matters associated with former MGP and waste disposal sites of the Ameren Companies; |
• | litigation associated with the breach of the upper reservoir at Ameren Missouri's Taum Sauk pumped-storage hydroelectric energy center; |
• | Ameren Illinois' receipt of tax liability notices relating to prior-period electric and natural gas municipal taxes; and |
• | asbestos-related litigation associated with Ameren, Ameren Missouri and Ameren Illinois. |
Period | (a) Total Number of Shares (or Units) Purchased(a) | (b) Average Price Paid per Share (or Unit) | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | ||||||||
April 1 - April 30, 2014 | — | $ | — | — | — | |||||||
May 1 - May 31, 2014 | 1,895 | 40.60 | — | — | ||||||||
June 1 - June 30, 2014 | — | — | — | — | ||||||||
Total | 1,895 | $ | 40.60 | — | — |
(a) | Included in May were 1,895 shares of Ameren common stock purchased in open-market transactions pursuant to Ameren’s 2006 Incentive Plan in satisfaction of Ameren’s obligations for Ameren board of directors’ compensation awards. Ameren does not have any publicly announced equity securities repurchase plans or programs. |
Exhibit Designation | Registrant(s) | Nature of Exhibit | Previously Filed as Exhibit to: | |||
Instruments Defining the Rights of Security Holders, Including Indentures | ||||||
4.1 | Ameren Ameren Missouri | Ameren Missouri Indenture Company Order dated April 4, 2014, establishing the 3.50% Senior Secured Notes due 2024 | April 4, 2014 Form 8-K, Exhibit 4.2, File No. 1-2967 | |||
4.2 | Ameren Ameren Missouri | Global Note, dated April 4, 2014, representing the 3.50% Senior Secured Notes due 2024 | April 4, 2014 Form 8-K, Exhibit 4.3, File No. 1-2967 | |||
4.3 | Ameren Ameren Missouri | Supplemental Indenture to the Ameren Missouri Mortgage dated April 1, 2014, relative to Series PP | April 4, 2014 Form 8-K, Exhibit 4.5, File No. 1-2967 | |||
4.4 | Ameren Ameren Illinois | Ameren Illinois Indenture Company Order dated June 30, 2014, establishing the 4.30% Senior Secured Notes due 2044 | June 30, 2014 Form 8-K, Exhibit 4.2, File No. 1-3672 | |||
4.5 | Ameren Ameren Illinois | Global Note, dated June 30, 2014, representing the 4.30% Senior Secured Notes due 2044 | June 30, 2014 Form 8-K, Exhibit 4.3, File No. 1-3672 | |||
4.6 | Ameren Ameren Illinois | Supplemental Indenture to the Ameren Illinois Mortgage dated as of June 1, 2014, relative to Series GG | June 30, 2014 Form 8-K, Exhibit 4.5, File No. 1-3672 | |||
Material Contracts | ||||||
10.1* | Ameren Companies | Ameren Corporation 2014 Omnibus Incentive Compensation Plan | Exhibit 99, File No. 333-196515 | |||
10.2* | Ameren Companies | Form of Performance Share Unit Award Agreement for Awards Issued in 2014 pursuant to 2014 Omnibus Incentive Compensation Plan | ||||
Statement re: Computation of Ratios | ||||||
12.1 | Ameren | Ameren's Statement of Computation of Ratio of Earnings to Fixed Charges | ||||
12.2 | Ameren Missouri | Ameren Missouri's Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | ||||
12.3 | Ameren Illinois | Ameren Illinois’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements | ||||
Rule 13a-14(a) / 15d-14(a) Certifications | ||||||
31.1 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren | ||||
31.2 | Ameren | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren | ||||
31.3 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Missouri | ||||
31.4 | Ameren Missouri | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Missouri | ||||
31.5 | Ameren Illinois | Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren Illinois | ||||
31.6 | Ameren Illinois | Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren Illinois | ||||
Section 1350 Certifications | ||||||
32.1 | Ameren | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren | ||||
32.2 | Ameren Missouri | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Missouri | ||||
32.3 | Ameren Illinois | Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren Illinois | ||||
Interactive Data Files | ||||||
101.INS | Ameren Companies | XBRL Instance Document | ||||
101.SCH | Ameren Companies | XBRL Taxonomy Extension Schema Document | ||||
101.CAL | Ameren Companies | XBRL Taxonomy Extension Calculation Linkbase Document | ||||
101.LAB | Ameren Companies | XBRL Taxonomy Extension Label Linkbase Document | ||||
101.PRE | Ameren Companies | XBRL Taxonomy Extension Presentation Linkbase Document | ||||
101.DEF | Ameren Companies | XBRL Taxonomy Extension Definition Document |
AMEREN CORPORATION (Registrant) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
UNION ELECTRIC COMPANY (Registrant) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
AMEREN ILLINOIS COMPANY (Registrant) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
ARTICLE 1 | PAGE | ||||
ESTABLISHMENT, EFFECTIVENESS, PURPOSE AND DURATION | |||||
Section 1.01. | Establishment | 1 | |||
Section 1.02. | Effectiveness | 1 | |||
Section 1.03. | Purpose of This Plan | 1 | |||
Section 1.04. | Duration of This Plan | 1 | |||
ARTICLE 2 | |||||
DEFINITIONS | |||||
ARTICLE 3 | |||||
ADMINISTRATION | |||||
Section 3.01. | General | 5 | |||
Section 3.02. | Authority of the Committee | 5 | |||
Section 3.03. | Delegation | 6 | |||
ARTICLE 4 | |||||
SHARES SUBJECT TO THIS PLAN AND MAXIMUM AWARDS | |||||
Section 4.01. | Number of Shares Available for Awards | 6 | |||
Section 4.02. | Share Usage | 7 | |||
Section 4.03. | Annual Award Limits | 7 | |||
Section 4.04. | Adjustments in Authorized Shares | 8 | |||
Section 4.05. | Source of Shares | 8 | |||
ARTICLE 5 | |||||
ELIGIBILITY AND PARTICIPATION | |||||
Section 5.01. | Eligibility | 9 | |||
Section 5.02. | Actual Participation | 9 | |||
ARTICLE 6 | |||||
STOCK OPTIONS | |||||
Section 6.01. | Grant of Options | 9 | |||
Section 6.02. | Award Agreement | 9 | |||
Section 6.03. | Option Price | 9 | |||
Section 6.04. | Term of Options | 9 | |||
Section 6.05. | Exercise of Options | 9 | |||
Section 6.06. | Payment | 9 | |||
Section 6.07. | Restrictions on Share Transferability | 10 | |||
Section 6.08. | Termination of Employment | 10 |
Section 6.09. | Automatic Option Exercise | 10 | |||
ARTICLE 7 | |||||
STOCK APPRECIATION RIGHTS | |||||
Section 7.01. | Grant of SARs | 11 | |||
Section 7.02. | SAR Award Agreement | 11 | |||
Section 7.03. | Grant Price | 11 | |||
Section 7.04. | Term of SAR | 11 | |||
Section 7.05. | Exercise of SARs | 11 | |||
Section 7.06. | Settlement of SARs | 11 | |||
Section 7.07. | Termination of Employment | 12 | |||
Section 7.08. | Other Restrictions | 12 | |||
Section 7.09. | Automatic SAR Exercise | 12 | |||
ARTICLE 8 | |||||
RESTRICTED STOCK AND RESTRICTED STOCK UNITS | |||||
Section 8.01. | Grant of Restricted Stock or Restricted Stock Units | 12 | |||
Section 8.02. | Restricted Stock or Restricted Stock Unit Award Agreement | 12 | |||
Section 8.03. | Other Restrictions | 12 | |||
Section 8.04. | Certificate Legend | 13 | |||
Section 8.05. | Voting Rights | 13 | |||
Section 8.06. | Termination of Employment | 13 | |||
ARTICLE 9 | |||||
PERFORMANCE UNITS / PERFORMANCE SHARES | |||||
Section 9.01. | Grant of Performance Units / Performance Shares | 14 | |||
Section 9.02. | Value of Performance Units / Performance Shares | 14 | |||
Section 9.03. | Earning of Performance Units / Performance Shares | 14 | |||
Section 9.04. | Form and Timing of Payment of Performance Units / Performance Shares | 14 | |||
Section 9.05. | Termination of Employment | 14 | |||
ARTICLE 10 | |||||
CASH-BASED AWARDS AND OTHER STOCK-BASED AWARDS | |||||
Section 10.01. | Grant of Cash-Based Awards | 15 | |||
Section 10.02. | Other Stock-Based Awards | 15 | |||
Section 10.03. | Value of Cash-Based and Other Stock-Based Awards | 15 | |||
Section 10.04. | Payment of Cash-Based Awards and Other Stock-Based Awards | 15 | |||
Section 10.05. | Termination of Employment | 15 | |||
ARTICLE 11 | |||||
TRANSFERABILITY OF AWARDS | |||||
Section 11.01. | Transferability | 15 | |||
Section 11.02. | Committee Action | 16 | |||
ARTICLE 12 | |||||
PERFORMANCE MEASURES | |||||
Section 12.01. | Awards Under This Article 12 | 16 | |||
Section 12.02. | Performance Goals | 16 | |||
Section 12.03. | Performance Measures | 16 | |||
Section 12.04. | Evaluation of Performance | 17 | |||
Section 12.05. | Certification of Performance | 17 | |||
Section 12.06. | Adjustment of Performance-Based Compensation | 17 | |||
Section 12.07. | Committee Discretion | 17 | |||
ARTICLE 13 | |||||
DIRECTOR AWARDS | |||||
ARTICLE 14 | |||||
DIVIDEND EQUIVALENTS | |||||
ARTICLE 15 | |||||
BENEFICIARY DESIGNATION | |||||
ARTICLE 16 | |||||
RIGHTS OF PARTICIPANTS | |||||
Section 16.01. | Employment | 18 | |||
Section 16.02. | Participation | 19 | |||
Section 16.03. | Rights as a Shareholder | 19 | |||
ARTICLE 17 | |||||
CHANGE OF CONTROL | |||||
ARTICLE 18 | |||||
AMENDMENT, MODIFICATION, SUSPENSION, AND TERMINATION | |||||
Section 18.01. | Amendment, Modification, Suspension, and Termination | 19 | |||
Section 18.02. | Awards Previously Granted | 19 | |||
Section 18.03. | Amendment to Conform to Law | 19 | |||
ARTICLE 19 | |||||
WITHHOLDING | |||||
ARTICLE 20 | |||||
SUCCESSORS | |||||
ARTICLE 21 | |||||
GENERAL PROVISIONS | |||||
Section 21.01. | Forfeiture Events | 20 | |||
Section 21.02. | Legend | 21 | |||
Section 21.03. | Gender and Number | 21 | |||
Section 21.04. | Severability | 21 | |||
Section 21.05. | Requirements of Law | 21 | |||
Section 21.06. | Delivery of Title | 21 | |||
Section 21.07. | Inability to Obtain Authority | 21 | |||
Section 21.08. | Investment Representations | 22 | |||
Section 21.09. | Uncertificated Shares | 22 | |||
Section 21.10. | Unfunded Plan | 22 | |||
Section 21.11. | No Fractional Shares | 22 | |||
Section 21.12. | Retirement and Welfare Plans | 22 | |||
Section 21.13. | Deferred Compensation | 22 | |||
Section 21.14. | Nonexclusivity of this Plan | 23 | |||
Section 21.15. | No Constraint on Corporate Action | 23 | |||
Section 21.16. | Governing Law | 23 | |||
Section 21.17. | Indemnification | 23 | |||
Section 21.18. | No Guarantee of Favorable Tax Treatment | 23 | |||
Section 21.19. | Effect of Disposition of Facility or Operating Unit | 24 |
Six Months Ended June 30, | |||
2014 | |||
Earnings available for fixed charges, as defined: | |||
Net income from continuing operations attributable to Ameren Corporation | $ | 246,809 | |
Income from equity investee | (284 | ) | |
Distributed income from equity investee | 510 | ||
Tax expense based on income | 162,789 | ||
Fixed charges excluding subsidiary preferred stock dividends tax adjustment (a) | 197,661 | ||
Earnings available for fixed charges, as defined | $ | 607,485 | |
Fixed charges, as defined: | |||
Interest expense on short-term and long-term debt (a) | $ | 179,146 | |
Estimated interest cost within rental expense | 4,351 | ||
Amortization of net debt premium, discount, and expenses | 10,942 | ||
Subsidiary preferred stock dividends | 3,222 | ||
Adjust subsidiary preferred stock dividends to pretax basis | 2,043 | ||
Total fixed charges, as defined | $ | 199,704 | |
Consolidated ratio of earnings to fixed charges | 3.04 |
(a) | Includes net interest related to uncertain tax positions. |
Six Months Ended June 30, | |||
2014 | |||
Earnings available for fixed charges, as defined: | |||
Net income | $ | 174,248 | |
Tax expense based on income | 104,550 | ||
Fixed charges (a) | 116,603 | ||
Earnings available for fixed charges, as defined | $ | 395,401 | |
Fixed charges, as defined: | |||
Interest expense on short-term and long-term debt (a) | $ | 110,894 | |
Estimated interest cost within rental expense | 2,183 | ||
Amortization of net debt premium, discount, and expenses | 3,526 | ||
Total fixed charges, as defined | $ | 116,603 | |
Ratio of earnings to fixed charges | 3.39 | ||
Earnings required for combined fixed charges and preferred stock dividends: | |||
Preferred stock dividends | $ | 1,710 | |
Adjustment to pretax basis | 1,026 | ||
$ | 2,736 | ||
Combined fixed charges and preferred stock dividend requirements | $ | 119,339 | |
Ratio of earnings to combined fixed charges and preferred stock dividend requirements | 3.31 |
(a) | Includes net interest related to uncertain tax positions. |
Six Months Ended June 30, | |||
2014 | |||
Earnings available for fixed charges, as defined: | |||
Net income | $ | 82,903 | |
Tax expense based on income | 55,773 | ||
Fixed charges (a) | 61,638 | ||
Earnings available for fixed charges, as defined | $ | 200,314 | |
Fixed charges, as defined: | |||
Interest expense on short-term and long-term debt (a) | $ | 53,094 | |
Estimated interest cost within rental expense | 2,145 | ||
Amortization of net debt premium, discount, and expenses | 6,399 | ||
Total fixed charges, as defined | $ | 61,638 | |
Ratio of earnings to fixed charges | 3.25 | ||
Earnings required for combined fixed charges and preferred stock dividends: | |||
Preferred stock dividends | $ | 1,512 | |
Adjustment to pretax basis | 1,017 | ||
$ | 2,529 | ||
Combined fixed charges and preferred stock dividend requirements | $ | 64,167 | |
Ratio of earnings to combined fixed charges and preferred stock dividend requirements | 3.12 |
(a) | Includes net interest related to uncertain tax positions. |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Warner L. Baxter |
Warner L. Baxter Chairman, President and Chief Executive Officer (Principal Executive Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Michael L. Moehn |
Michael L. Moehn Chairman, President and Chief Executive Officer (Principal Executive Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Richard J. Mark |
Richard J. Mark Chairman, President and Chief Executive Officer (Principal Executive Officer) |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
(1) | The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and |
(2) | The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
/s/ Warner L. Baxter |
Warner L. Baxter Chairman, President and Chief Executive Officer (Principal Executive Officer) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
(1) | The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and |
(2) | The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
/s/ Michael L. Moehn |
Michael L. Moehn Chairman, President and Chief Executive Officer (Principal Executive Officer) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
(1) | The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and |
(2) | The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Registrant. |
/s/ Richard J. Mark |
Richard J. Mark Chairman, President and Chief Executive Officer (Principal Executive Officer) |
/s/ Martin J. Lyons, Jr. |
Martin J. Lyons, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
Summary Of Significant Accounting Policies (Schedule Of Excise Taxes) (Detail) (USD $)
In Millions, unless otherwise specified |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2014
|
Jun. 30, 2013
|
Jun. 30, 2014
|
Jun. 30, 2013
|
|
Accounting Policies [Line Items] | ||||
Excise tax expense | $ 50 | $ 49 | $ 110 | $ 104 |
Union Electric Company
|
||||
Accounting Policies [Line Items] | ||||
Excise tax expense | 39 | 38 | 73 | 71 |
Ameren Illinois Company
|
||||
Accounting Policies [Line Items] | ||||
Excise tax expense | $ 11 | $ 11 | $ 37 | $ 33 |
Derivative Financial Instruments (Derivative Instruments Carrying Value) (Detail) (Not Designated As Hedging Instrument [Member], USD $)
In Millions, unless otherwise specified |
Jun. 30, 2014
|
Dec. 31, 2013
|
---|---|---|
Derivative [Line Items] | ||
Derivative assets | $ 34 | $ 34 |
Derivative liabilities | 149 | 178 |
Fuel Oils | Other Current Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 5 | 6 |
Fuel Oils | Other Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 2 | 3 |
Fuel Oils | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 2 | 2 |
Fuel Oils | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 1 | 1 |
Natural Gas | Other Current Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 4 | 2 |
Natural Gas | Other Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 1 | |
Natural Gas | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 20 | 32 |
Natural Gas | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 10 | 25 |
Power | Other Current Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 22 | 23 |
Power | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 13 | 13 |
Power | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 96 | 99 |
Uranium | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 5 | 5 |
Uranium | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 2 | 1 |
Union Electric Company
|
||
Derivative [Line Items] | ||
Derivative assets | 30 | 33 |
Derivative liabilities | 22 | 24 |
Union Electric Company | Fuel Oils | Other Current Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 5 | 6 |
Union Electric Company | Fuel Oils | Other Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 2 | 3 |
Union Electric Company | Fuel Oils | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 2 | 2 |
Union Electric Company | Fuel Oils | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 1 | 1 |
Union Electric Company | Natural Gas | Other Current Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 1 | 1 |
Union Electric Company | Natural Gas | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 4 | 5 |
Union Electric Company | Natural Gas | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 2 | 6 |
Union Electric Company | Power | Other Current Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 22 | 23 |
Union Electric Company | Power | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 6 | 4 |
Union Electric Company | Uranium | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 5 | 5 |
Union Electric Company | Uranium | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 2 | 1 |
Ameren Illinois Company
|
||
Derivative [Line Items] | ||
Derivative assets | 4 | 1 |
Derivative liabilities | 127 | 154 |
Ameren Illinois Company | Natural Gas | Other Current Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 3 | 1 |
Ameren Illinois Company | Natural Gas | Other Assets [Member]
|
||
Derivative [Line Items] | ||
Derivative assets | 1 | |
Ameren Illinois Company | Natural Gas | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 16 | 27 |
Ameren Illinois Company | Natural Gas | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 8 | 19 |
Ameren Illinois Company | Power | Other Current Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | 7 | 9 |
Ameren Illinois Company | Power | Other Deferred Credits And Liabilities [Member]
|
||
Derivative [Line Items] | ||
Derivative liabilities | $ 96 | $ 99 |
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