Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Billions, except Share data, unless otherwise specified | Dec. 31, 2014 | Jan. 31, 2015 | Jun. 30, 2014 |
Document Information [Line Items] | |||
Entity Registrant Name | SOUTHERN CO | ||
Entity Central Index Key | 92122 | ||
Document Type | 10-K | ||
Document Period End Date | 31-Dec-14 | ||
Amendment Flag | FALSE | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $40.70 | ||
Entity Common Stock, Shares Outstanding | 909,877,898 | ||
Alabama Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | ALABAMA POWER CO | ||
Entity Central Index Key | 3153 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 30,537,500 | ||
Georgia Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | GEORGIA POWER CO | ||
Entity Central Index Key | 41091 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 9,261,500 | ||
Gulf Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | GULF POWER CO | ||
Entity Central Index Key | 44545 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 5,642,717 | ||
Mississippi Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | MISSISSIPPI POWER CO | ||
Entity Central Index Key | 66904 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 1,121,000 | ||
Southern Power [Member] | |||
Document Information [Line Items] | |||
Entity Registrant Name | SOUTHERN POWER CO | ||
Entity Central Index Key | 1160661 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 1,000 |
Consolidated_Statements_of_Inc
Consolidated Statements of Income (USD $) | 12 Months Ended | |||||
Share data in Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Operating Revenues: | ||||||
Retail revenues | $15,550,000,000 | $14,541,000,000 | $14,187,000,000 | |||
Wholesale Revenues | 2,184,000,000 | 1,855,000,000 | 1,675,000,000 | |||
Other Electric Revenues | 672,000,000 | 639,000,000 | 616,000,000 | |||
Other revenues | 61,000,000 | 52,000,000 | 59,000,000 | |||
Total operating revenues | 18,467,000,000 | 17,087,000,000 | 16,537,000,000 | |||
Operating Expenses: | ||||||
Fuel | 6,005,000,000 | 5,510,000,000 | 5,057,000,000 | |||
Cost of Purchased Power | 672,000,000 | 461,000,000 | 544,000,000 | |||
Other operations and maintenance | 4,354,000,000 | 3,846,000,000 | 3,772,000,000 | |||
Depreciation and amortization | 1,945,000,000 | 1,901,000,000 | 1,787,000,000 | |||
Taxes other than income taxes | 981,000,000 | 934,000,000 | 914,000,000 | |||
Estimated loss on Kemper IGCC | 868,000,000 | 1,180,000,000 | 0 | |||
Total operating expenses | 14,825,000,000 | 13,832,000,000 | 12,074,000,000 | |||
Operating Income | 3,642,000,000 | 3,255,000,000 | 4,463,000,000 | |||
Other Income and (Expense): | ||||||
Allowance for equity funds used during construction | 245,000,000 | 190,000,000 | 143,000,000 | |||
Interest income | 19,000,000 | 19,000,000 | 40,000,000 | |||
Interest expense, net of amounts capitalized | -835,000,000 | -824,000,000 | -859,000,000 | |||
Other income (expense), net | -63,000,000 | -81,000,000 | -38,000,000 | |||
Total other income and (expense) | -634,000,000 | -696,000,000 | -714,000,000 | |||
Earnings Before Income Taxes | 3,008,000,000 | 2,559,000,000 | 3,749,000,000 | |||
Income taxes | 977,000,000 | 849,000,000 | 1,334,000,000 | |||
Net Income (loss) | 2,031,000,000 | 1,710,000,000 | 2,415,000,000 | |||
Dividends on Preferred and Preference Stock | 68,000,000 | 66,000,000 | 65,000,000 | |||
Net Income After Dividends on Preferred and Preference Stock | 1,963,000,000 | [1],[2] | 1,644,000,000 | [1],[2] | 2,350,000,000 | [1] |
Earnings per share (EPS) — | ||||||
Basic EPS, Per Common Share (in dollars per share) | $2.19 | $1.88 | $2.70 | |||
Diluted EPS, Per Common Share (in dollars per share) | $2.18 | $1.87 | $2.67 | |||
Average number of shares of common stock outstanding — (in millions) | ||||||
Basic shares | 897 | 877 | 871 | |||
Diluted shares | 901 | 881 | 879 | |||
Alabama Power [Member] | ||||||
Operating Revenues: | ||||||
Retail revenues | 5,249,000,000 | 4,952,000,000 | 4,933,000,000 | |||
Wholesale revenues, non-affiliates | 281,000,000 | 248,000,000 | 277,000,000 | |||
Wholesale revenues, affiliates | 189,000,000 | 212,000,000 | 111,000,000 | |||
Other revenues | 223,000,000 | 206,000,000 | 199,000,000 | |||
Total operating revenues | 5,942,000,000 | 5,618,000,000 | 5,520,000,000 | |||
Operating Expenses: | ||||||
Fuel | 1,605,000,000 | 1,631,000,000 | 1,503,000,000 | |||
Purchased power, non-affiliates | 185,000,000 | 100,000,000 | 73,000,000 | |||
Purchased power, affiliates | 200,000,000 | 129,000,000 | 182,000,000 | |||
Other operations and maintenance | 1,468,000,000 | 1,289,000,000 | 1,287,000,000 | |||
Depreciation and amortization | 603,000,000 | 645,000,000 | 639,000,000 | |||
Taxes other than income taxes | 356,000,000 | 348,000,000 | 340,000,000 | |||
Total operating expenses | 4,417,000,000 | 4,142,000,000 | 4,024,000,000 | |||
Operating Income | 1,525,000,000 | 1,476,000,000 | 1,496,000,000 | |||
Other Income and (Expense): | ||||||
Allowance for equity funds used during construction | 49,000,000 | 32,000,000 | 19,000,000 | |||
Interest income | 15,000,000 | 16,000,000 | 16,000,000 | |||
Interest expense, net of amounts capitalized | -255,000,000 | -259,000,000 | -287,000,000 | |||
Other income (expense), net | -22,000,000 | -36,000,000 | -24,000,000 | |||
Total other income and (expense) | -213,000,000 | -247,000,000 | -276,000,000 | |||
Earnings Before Income Taxes | 1,312,000,000 | 1,229,000,000 | 1,220,000,000 | |||
Income taxes | 512,000,000 | 478,000,000 | 477,000,000 | |||
Net Income (loss) | 800,000,000 | 751,000,000 | 743,000,000 | |||
Dividends on Preferred and Preference Stock | 39,000,000 | 39,000,000 | 39,000,000 | |||
Net Income After Dividends on Preferred and Preference Stock | 761,000,000 | 712,000,000 | 704,000,000 | |||
Georgia Power [Member] | ||||||
Operating Revenues: | ||||||
Retail revenues | 8,240,000,000 | 7,620,000,000 | 7,362,000,000 | |||
Wholesale revenues, non-affiliates | 335,000,000 | 281,000,000 | 281,000,000 | |||
Wholesale revenues, affiliates | 42,000,000 | 20,000,000 | 20,000,000 | |||
Other revenues | 371,000,000 | 353,000,000 | 335,000,000 | |||
Total operating revenues | 8,988,000,000 | 8,274,000,000 | 7,998,000,000 | |||
Operating Expenses: | ||||||
Fuel | 2,547,000,000 | 2,307,000,000 | 2,051,000,000 | |||
Purchased power, non-affiliates | 287,000,000 | 224,000,000 | 315,000,000 | |||
Purchased power, affiliates | 701,000,000 | 660,000,000 | 666,000,000 | |||
Other operations and maintenance | 1,902,000,000 | 1,654,000,000 | 1,644,000,000 | |||
Depreciation and amortization | 846,000,000 | 807,000,000 | 745,000,000 | |||
Taxes other than income taxes | 409,000,000 | 382,000,000 | 374,000,000 | |||
Total operating expenses | 6,692,000,000 | 6,034,000,000 | 5,795,000,000 | |||
Operating Income | 2,296,000,000 | 2,240,000,000 | 2,203,000,000 | |||
Other Income and (Expense): | ||||||
Allowance for equity funds used during construction | 45,000,000 | 30,000,000 | 53,000,000 | |||
Interest expense, net of amounts capitalized | -348,000,000 | -361,000,000 | -366,000,000 | |||
Other income (expense), net | -22,000,000 | 5,000,000 | -17,000,000 | |||
Total other income and (expense) | -325,000,000 | -326,000,000 | -330,000,000 | |||
Earnings Before Income Taxes | 1,971,000,000 | 1,914,000,000 | 1,873,000,000 | |||
Income taxes | 729,000,000 | 723,000,000 | 688,000,000 | |||
Net Income (loss) | 1,242,000,000 | 1,191,000,000 | 1,185,000,000 | |||
Dividends on Preferred and Preference Stock | 17,000,000 | 17,000,000 | 17,000,000 | |||
Net Income After Dividends on Preferred and Preference Stock | 1,225,000,000 | 1,174,000,000 | 1,168,000,000 | |||
Gulf Power [Member] | ||||||
Operating Revenues: | ||||||
Retail revenues | 1,266,540,000 | 1,170,000,000 | 1,144,471,000 | |||
Wholesale revenues, non-affiliates | 129,151,000 | 109,386,000 | 106,881,000 | |||
Wholesale revenues, affiliates | 130,107,000 | 99,577,000 | 123,636,000 | |||
Other revenues | 64,684,000 | 61,338,000 | 64,774,000 | |||
Total operating revenues | 1,590,482,000 | 1,440,301,000 | 1,439,762,000 | |||
Operating Expenses: | ||||||
Fuel | 604,641,000 | 532,791,000 | 544,936,000 | |||
Purchased power, non-affiliates | 81,993,000 | 52,443,000 | 51,421,000 | |||
Purchased power, affiliates | 25,246,000 | 32,835,000 | 22,665,000 | |||
Other operations and maintenance | 341,214,000 | 309,865,000 | 314,195,000 | |||
Depreciation and amortization | 145,026,000 | 149,009,000 | 141,038,000 | |||
Taxes other than income taxes | 111,147,000 | 98,355,000 | 97,313,000 | |||
Total operating expenses | 1,309,267,000 | 1,175,298,000 | 1,171,568,000 | |||
Operating Income | 281,215,000 | 265,003,000 | 268,194,000 | |||
Other Income and (Expense): | ||||||
Allowance for equity funds used during construction | 12,021,000 | 6,448,000 | 5,221,000 | |||
Interest income | 90,000 | 369,000 | 1,408,000 | |||
Interest expense, net of amounts capitalized | -53,234,000 | -56,025,000 | -60,250,000 | |||
Other income (expense), net | -2,851,000 | -3,994,000 | -3,227,000 | |||
Total other income and (expense) | -43,974,000 | -53,202,000 | -56,848,000 | |||
Earnings Before Income Taxes | 237,241,000 | 211,801,000 | 211,346,000 | |||
Income taxes | 88,062,000 | 79,668,000 | 79,211,000 | |||
Net Income (loss) | 149,179,000 | 132,133,000 | 132,135,000 | |||
Dividends on Preferred and Preference Stock | 9,003,000 | 7,704,000 | 6,203,000 | |||
Net Income After Dividends on Preferred and Preference Stock | 140,176,000 | 124,429,000 | 125,932,000 | |||
Mississippi Power [Member] | ||||||
Operating Revenues: | ||||||
Retail revenues | 794,643,000 | 799,139,000 | 747,453,000 | |||
Wholesale revenues, non-affiliates | 322,659,000 | 293,871,000 | 255,557,000 | |||
Wholesale revenues, affiliates | 107,210,000 | 34,773,000 | 16,403,000 | |||
Other revenues | 18,099,000 | 17,374,000 | 16,583,000 | |||
Total operating revenues | 1,242,611,000 | 1,145,157,000 | 1,035,996,000 | |||
Operating Expenses: | ||||||
Fuel | 573,936,000 | 491,250,000 | 411,226,000 | |||
Purchased power, non-affiliates | 17,848,000 | 5,752,000 | 5,221,000 | |||
Purchased power, affiliates | 25,096,000 | 42,579,000 | 49,907,000 | |||
Other operations and maintenance | 270,669,000 | 253,329,000 | 228,675,000 | |||
Depreciation and amortization | 97,120,000 | 91,398,000 | 86,510,000 | |||
Taxes other than income taxes | 79,112,000 | 80,694,000 | 79,445,000 | |||
Estimated loss on Kemper IGCC | 868,000,000 | 1,102,000,000 | 78,000,000 | |||
Total operating expenses | 1,931,781,000 | 2,067,002,000 | 938,984,000 | |||
Operating Income | -689,170,000 | -921,845,000 | 97,012,000 | |||
Other Income and (Expense): | ||||||
Allowance for equity funds used during construction | 136,436,000 | 121,629,000 | 64,793,000 | |||
Interest expense, net of amounts capitalized | -45,322,000 | -36,481,000 | -40,838,000 | |||
Other income (expense), net | -14,097,000 | -6,030,000 | 1,264,000 | |||
Total other income and (expense) | 77,017,000 | 79,118,000 | 25,219,000 | |||
Earnings Before Income Taxes | -612,153,000 | -842,727,000 | 122,231,000 | |||
Income taxes | -285,205,000 | -367,835,000 | 20,556,000 | |||
Net Income (loss) | -326,948,000 | -474,892,000 | 101,675,000 | |||
Dividends on Preferred and Preference Stock | 1,733,000 | 1,733,000 | 1,733,000 | |||
Net Income After Dividends on Preferred and Preference Stock | -328,681,000 | -476,625,000 | 99,942,000 | |||
Southern Power [Member] | ||||||
Operating Revenues: | ||||||
Wholesale revenues, non-affiliates | 1,115,880,000 | 922,811,000 | 753,653,000 | |||
Wholesale revenues, affiliates | 382,523,000 | 345,799,000 | 425,180,000 | |||
Other revenues | 2,846,000 | 6,616,000 | 7,215,000 | |||
Total operating revenues | 1,501,249,000 | 1,275,226,000 | 1,186,048,000 | |||
Operating Expenses: | ||||||
Fuel | 596,319,000 | 473,805,000 | 426,257,000 | |||
Purchased power, non-affiliates | 104,871,000 | 75,954,000 | 80,438,000 | |||
Purchased power, affiliates | 66,033,000 | 30,415,000 | 12,915,000 | |||
Other operations and maintenance | 237,061,000 | 208,366,000 | 173,074,000 | |||
Depreciation and amortization | 220,174,000 | 175,295,000 | 142,624,000 | |||
Taxes other than income taxes | 21,512,000 | 21,416,000 | 19,309,000 | |||
Total operating expenses | 1,245,970,000 | 985,251,000 | 854,617,000 | |||
Operating Income | 255,279,000 | 289,975,000 | 331,431,000 | |||
Other Income and (Expense): | ||||||
Interest expense, net of amounts capitalized | -88,992,000 | -74,475,000 | -62,503,000 | |||
Other income (expense), net | 5,560,000 | -4,072,000 | -1,022,000 | |||
Total other income and (expense) | -83,432,000 | -78,547,000 | -63,525,000 | |||
Earnings Before Income Taxes | 171,847,000 | 211,428,000 | 267,906,000 | |||
Income taxes | -3,228,000 | 45,895,000 | 92,621,000 | |||
Net Income (loss) | 175,075,000 | 165,533,000 | 175,285,000 | |||
Less: Net income attributable to noncontrolling interests | 2,775,000 | 0 | 0 | |||
Net Income (Loss) Attributable to Parent | $172,300,000 | $165,533,000 | $175,285,000 | |||
[1] | After dividends on preferred and preference stock of subsidiaries. | |||||
[2] | Segment net income (loss) for the traditional operating companies in 2014 and 2013 includes $868 million in pre-tax charges ($536 million after tax) and $1.2 billion in pre-tax charges ($729 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Net Income (Loss) | $2,031,000,000 | $1,710,000,000 | $2,415,000,000 |
Qualifying hedges: | |||
Changes in fair value, net of tax | -10,000,000 | 0 | -12,000,000 |
Reclassification adjustment for amounts included in net income, net of tax | 5,000,000 | 9,000,000 | 11,000,000 |
Marketable securities: | |||
Change in fair value, net of tax | 0 | -3,000,000 | 0 |
Pension and other postretirement benefit plans: | |||
Benefit plan net gain (loss),net of tax | -51,000,000 | 36,000,000 | -3,000,000 |
Reclassification adjustment for amounts included in net income, net of tax | 3,000,000 | 6,000,000 | -8,000,000 |
Total other comprehensive income (loss) | -53,000,000 | 48,000,000 | -12,000,000 |
Dividends on Preferred and Preference Stock | 68,000,000 | 66,000,000 | 65,000,000 |
Comprehensive Income | 1,910,000,000 | 1,692,000,000 | 2,338,000,000 |
Alabama Power [Member] | |||
Net Income (Loss) | 800,000,000 | 751,000,000 | 743,000,000 |
Qualifying hedges: | |||
Changes in fair value, net of tax | -5,000,000 | 0 | -11,000,000 |
Reclassification adjustment for amounts included in net income, net of tax | 2,000,000 | 1,000,000 | 2,000,000 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | -3,000,000 | 1,000,000 | -9,000,000 |
Dividends on Preferred and Preference Stock | 39,000,000 | 39,000,000 | 39,000,000 |
Comprehensive Income | 797,000,000 | 752,000,000 | 734,000,000 |
Georgia Power [Member] | |||
Net Income (Loss) | 1,242,000,000 | 1,191,000,000 | 1,185,000,000 |
Qualifying hedges: | |||
Changes in fair value, net of tax | -5,000,000 | 0 | 0 |
Reclassification adjustment for amounts included in net income, net of tax | 2,000,000 | 2,000,000 | 2,000,000 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | -3,000,000 | 2,000,000 | 2,000,000 |
Dividends on Preferred and Preference Stock | 17,000,000 | 17,000,000 | 17,000,000 |
Comprehensive Income | 1,239,000,000 | 1,193,000,000 | 1,187,000,000 |
Gulf Power [Member] | |||
Net Income (Loss) | 149,179,000 | 132,133,000 | 132,135,000 |
Qualifying hedges: | |||
Reclassification adjustment for amounts included in net income, net of tax | 372,000 | 472,000 | 573,000 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | 372,000 | 472,000 | 573,000 |
Dividends on Preferred and Preference Stock | 9,003,000 | 7,704,000 | 6,203,000 |
Comprehensive Income | 149,551,000 | 132,605,000 | 132,708,000 |
Mississippi Power [Member] | |||
Net Income (Loss) | -326,948,000 | -474,892,000 | 101,675,000 |
Qualifying hedges: | |||
Changes in fair value, net of tax | 0 | 0 | -479,000 |
Reclassification adjustment for amounts included in net income, net of tax | 849,000 | 849,000 | 663,000 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | 849,000 | 849,000 | 184,000 |
Dividends on Preferred and Preference Stock | 1,733,000 | 1,733,000 | 1,733,000 |
Comprehensive Income | -326,099,000 | -474,043,000 | 101,859,000 |
Southern Power [Member] | |||
Net Income (Loss) | 175,075,000 | 165,533,000 | 175,285,000 |
Qualifying hedges: | |||
Changes in fair value, net of tax | 0 | 0 | -136,000 |
Reclassification adjustment for amounts included in net income, net of tax | 367,000 | 3,695,000 | 6,189,000 |
Pension and other postretirement benefit plans: | |||
Total other comprehensive income (loss) | 367,000 | 3,695,000 | 6,053,000 |
Less: Comprehensive income attributable to noncontrolling interests | 2,775,000 | 0 | 0 |
Comprehensive Income | $172,667,000 | $169,228,000 | $181,338,000 |
Consolidated_Statements_of_Com1
Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Changes in fair value of qualifying hedges, tax | ($6,000,000) | $0 | ($7,000,000) |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 3,000,000 | 5,000,000 | 7,000,000 |
Change in fair value of marketable securities, tax | 0 | -2,000,000 | 0 |
Benefit plan net gain (loss), tax | -32,000,000 | 22,000,000 | -2,000,000 |
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax | 2,000,000 | 4,000,000 | -4,000,000 |
Alabama Power [Member] | |||
Changes in fair value of qualifying hedges, tax | -3,000,000 | 0 | -7,000,000 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 1,000,000 | 1,000,000 | 1,000,000 |
Georgia Power [Member] | |||
Changes in fair value of qualifying hedges, tax | -3,000,000 | 0 | 0 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 1,000,000 | 1,000,000 | 1,000,000 |
Gulf Power [Member] | |||
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 234,000 | 297,000 | 360,000 |
Mississippi Power [Member] | |||
Changes in fair value of qualifying hedges, tax | 0 | 0 | -296,000 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | 526,000 | 526,000 | 411,000 |
Southern Power [Member] | |||
Changes in fair value of qualifying hedges, tax | 0 | 0 | -90,000 |
Reclassification adjustment for amounts of qualifying hedges included in net income, tax | $169,000 | $2,357,000 | $3,919,000 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Operating Activities: | |||
Net Income (Loss) | $2,031,000,000 | $1,710,000,000 | $2,415,000,000 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 2,293,000,000 | 2,298,000,000 | 2,145,000,000 |
Deferred income taxes | 709,000,000 | 496,000,000 | 1,096,000,000 |
Investment tax credits | 35,000,000 | 302,000,000 | 128,000,000 |
Allowance for equity funds used during construction | -245,000,000 | -190,000,000 | -143,000,000 |
Pension, postretirement, and other employee benefits | -515,000,000 | 131,000,000 | -398,000,000 |
Stock based compensation expense | 63,000,000 | 59,000,000 | 55,000,000 |
Estimated loss on Kemper IGCC | 868,000,000 | 1,180,000,000 | 0 |
Amortization of Deferred Investment Tax Credits | -22,000,000 | -16,000,000 | -23,000,000 |
Other, net | -38,000,000 | -41,000,000 | 51,000,000 |
Changes in certain current assets and liabilities -- | |||
-Receivables | -352,000,000 | -153,000,000 | 234,000,000 |
-Fossil fuel stock | 408,000,000 | 481,000,000 | -452,000,000 |
-Materials and supplies | -67,000,000 | 36,000,000 | -97,000,000 |
-Other current assets | -57,000,000 | -11,000,000 | -37,000,000 |
-Accounts payable | 267,000,000 | 72,000,000 | -89,000,000 |
-Accrued taxes | -105,000,000 | -85,000,000 | -71,000,000 |
-Accrued compensation | 255,000,000 | -138,000,000 | -28,000,000 |
-Mirror CWIP | 180,000,000 | 0 | 0 |
-Other current liabilities | 85,000,000 | -50,000,000 | 89,000,000 |
Net cash provided from operating activities | 5,815,000,000 | 6,097,000,000 | 4,898,000,000 |
Investing Activities: | |||
Property additions | -5,977,000,000 | -5,463,000,000 | -4,809,000,000 |
Investment in restricted cash | -11,000,000 | -149,000,000 | -280,000,000 |
Distribution of restricted cash | 57,000,000 | 96,000,000 | 284,000,000 |
Nuclear decommissioning trust fund purchases | -916,000,000 | -986,000,000 | -1,046,000,000 |
Nuclear decommissioning trust fund sales | 914,000,000 | 984,000,000 | 1,043,000,000 |
Cost of removal, net of salvage | -170,000,000 | -131,000,000 | -149,000,000 |
Change in construction payables | -107,000,000 | -126,000,000 | -84,000,000 |
Prepaid Long-Term Service Agreement | -181,000,000 | -91,000,000 | -146,000,000 |
Other investing activities | -17,000,000 | 124,000,000 | 19,000,000 |
Net cash used for investing activities | -6,408,000,000 | -5,742,000,000 | -5,168,000,000 |
Financing Activities: | |||
Increase (decrease) in notes payable, net | -676,000,000 | 662,000,000 | -30,000,000 |
Proceeds -- | |||
Long-term debt issuances | 3,169,000,000 | 2,938,000,000 | 4,404,000,000 |
Interest-bearing refundable deposit related to asset sale | 125,000,000 | 0 | 150,000,000 |
Issuance of preference stock | 0 | 50,000,000 | 0 |
Common stock issuances | 806,000,000 | 695,000,000 | 397,000,000 |
Redemptions and repurchases -- | |||
Long-term debt | -816,000,000 | -2,830,000,000 | -3,169,000,000 |
Common stock repurchased | -5,000,000 | -20,000,000 | -430,000,000 |
Payment of common stock dividends | -1,866,000,000 | -1,762,000,000 | -1,693,000,000 |
Payment of dividends on preferred and preference stock of subsidiaries | -68,000,000 | -66,000,000 | -65,000,000 |
Other financing activities | -25,000,000 | 9,000,000 | 19,000,000 |
Net cash provided from (used for) financing activities | 644,000,000 | -324,000,000 | -417,000,000 |
Net Change in Cash and Cash Equivalents | 51,000,000 | 31,000,000 | -687,000,000 |
Cash and Cash Equivalents at Beginning of Year | 659,000,000 | 628,000,000 | 1,315,000,000 |
Cash and Cash Equivalents at End of Year | 710,000,000 | 659,000,000 | 628,000,000 |
Supplemental Cash Flow Information [Abstract] | |||
Interest paid, net of amounts capitalized | 732,000,000 | 759,000,000 | 803,000,000 |
Income taxes (net of refunds) | 272,000,000 | 139,000,000 | 38,000,000 |
Capital contributions from noncontrolling interests | 221,000,000 | ||
Alabama Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 800,000,000 | 751,000,000 | 743,000,000 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 724,000,000 | 816,000,000 | 767,000,000 |
Deferred income taxes | 270,000,000 | 198,000,000 | 164,000,000 |
Allowance for equity funds used during construction | -49,000,000 | -32,000,000 | -19,000,000 |
Pension, postretirement, and other employee benefits | -61,000,000 | 9,000,000 | -21,000,000 |
Stock based compensation expense | 11,000,000 | 10,000,000 | 9,000,000 |
Amortization of Deferred Investment Tax Credits | -8,000,000 | -8,000,000 | -8,000,000 |
Other, net | 17,000,000 | -38,000,000 | -24,000,000 |
Changes in certain current assets and liabilities -- | |||
-Receivables | -58,000,000 | 2,000,000 | 23,000,000 |
-Fossil fuel stock | 61,000,000 | 146,000,000 | -132,000,000 |
-Materials and supplies | -17,000,000 | 19,000,000 | -21,000,000 |
-Other current assets | -11,000,000 | 5,000,000 | -4,000,000 |
-Accounts payable | 157,000,000 | 35,000,000 | -77,000,000 |
-Accrued taxes | -199,000,000 | -23,000,000 | -12,000,000 |
-Accrued compensation | 50,000,000 | -23,000,000 | -3,000,000 |
-Retail fuel cost over-recovery—short-term | 5,000,000 | 42,000,000 | 1,000,000 |
-Other current liabilities | 9,000,000 | -3,000,000 | -18,000,000 |
Net cash provided from operating activities | 1,709,000,000 | 1,914,000,000 | 1,376,000,000 |
Investing Activities: | |||
Property additions | -1,457,000,000 | -1,107,000,000 | -867,000,000 |
Nuclear decommissioning trust fund purchases | -245,000,000 | -280,000,000 | -194,000,000 |
Nuclear decommissioning trust fund sales | 244,000,000 | 279,000,000 | 193,000,000 |
Cost of removal, net of salvage | -77,000,000 | -47,000,000 | -33,000,000 |
Change in construction payables | -10,000,000 | -13,000,000 | 12,000,000 |
Other investing activities | -22,000,000 | 26,000,000 | -45,000,000 |
Net cash used for investing activities | -1,567,000,000 | -1,142,000,000 | -934,000,000 |
Proceeds -- | |||
Capital contributions from parent company | 28,000,000 | 24,000,000 | 27,000,000 |
Pollution control revenue bonds issuances and remarketings | 254,000,000 | 0 | 0 |
Senior note issuances | 400,000,000 | 300,000,000 | 1,000,000,000 |
Redemptions and repurchases -- | |||
Pollution control revenue bonds | -254,000,000 | 0 | -1,000,000 |
Senior notes | 0 | -250,000,000 | -950,000,000 |
Payment of preferred and preference stock dividends | -39,000,000 | -39,000,000 | -39,000,000 |
Payment of common stock dividends | -550,000,000 | -644,000,000 | -684,000,000 |
Other financing activities | -3,000,000 | -5,000,000 | -2,000,000 |
Net cash provided from (used for) financing activities | -164,000,000 | -614,000,000 | -649,000,000 |
Net Change in Cash and Cash Equivalents | -22,000,000 | 158,000,000 | -207,000,000 |
Cash and Cash Equivalents at Beginning of Year | 295,000,000 | 137,000,000 | 344,000,000 |
Cash and Cash Equivalents at End of Year | 273,000,000 | 295,000,000 | 137,000,000 |
Supplemental Cash Flow Information [Abstract] | |||
Interest paid, net of amounts capitalized | 231,000,000 | 243,000,000 | 273,000,000 |
Income taxes (net of refunds) | 436,000,000 | 296,000,000 | 309,000,000 |
Noncash transactions - accrued property additions at year-end | 8,000,000 | 18,000,000 | 31,000,000 |
Georgia Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 1,242,000,000 | 1,191,000,000 | 1,185,000,000 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 1,019,000,000 | 979,000,000 | 912,000,000 |
Deferred income taxes | 352,000,000 | 476,000,000 | 377,000,000 |
Allowance for equity funds used during construction | -45,000,000 | -30,000,000 | -53,000,000 |
Retail fuel cost-recovery - long-term | -44,000,000 | -123,000,000 | 123,000,000 |
Pension, postretirement, and other employee benefits | 19,000,000 | 66,000,000 | 21,000,000 |
Pension and Other Postretirement Benefit Contributions | -156,000,000 | -8,000,000 | -12,000,000 |
Amortization of Deferred Investment Tax Credits | -10,000,000 | -5,000,000 | -13,000,000 |
Other, net | 39,000,000 | 38,000,000 | -12,000,000 |
Changes in certain current assets and liabilities -- | |||
-Receivables | -248,000,000 | -58,000,000 | 205,000,000 |
-Fossil fuel stock | 303,000,000 | 250,000,000 | -269,000,000 |
-Prepaid income taxes | -216,000,000 | -17,000,000 | -7,000,000 |
-Other current assets | -37,000,000 | 40,000,000 | -53,000,000 |
-Accounts payable | 16,000,000 | 67,000,000 | -165,000,000 |
-Accrued taxes | 17,000,000 | -14,000,000 | -76,000,000 |
-Accrued compensation | 62,000,000 | -37,000,000 | -18,000,000 |
-Retail fuel cost over-recovery—short-term | -14,000,000 | -49,000,000 | 107,000,000 |
-Other current liabilities | 54,000,000 | -5,000,000 | 30,000,000 |
Net cash provided from operating activities | 2,363,000,000 | 2,766,000,000 | 2,295,000,000 |
Investing Activities: | |||
Property additions | -2,023,000,000 | -1,743,000,000 | -1,723,000,000 |
Investment in restricted cash from pollution control bonds | 0 | -89,000,000 | -284,000,000 |
Distribution of restricted cash from pollution control revenue bonds | 0 | 89,000,000 | 284,000,000 |
Nuclear decommissioning trust fund purchases | -671,000,000 | -706,000,000 | -852,000,000 |
Nuclear decommissioning trust fund sales | 669,000,000 | 705,000,000 | 850,000,000 |
Cost of removal, net of salvage | -65,000,000 | -59,000,000 | -82,000,000 |
Change in construction payables, net of joint owner portion | -54,000,000 | -67,000,000 | -149,000,000 |
Prepaid Long-Term Service Agreement | -70,000,000 | -18,000,000 | -34,000,000 |
Other investing activities | 8,000,000 | -2,000,000 | 17,000,000 |
Net cash used for investing activities | -2,206,000,000 | -1,890,000,000 | -1,973,000,000 |
Financing Activities: | |||
Increase (decrease) in notes payable, net | -891,000,000 | 1,047,000,000 | -513,000,000 |
Proceeds -- | |||
Capital contributions from parent company | 549,000,000 | 37,000,000 | 42,000,000 |
Pollution control revenue bonds issuances and remarketings | 40,000,000 | 194,000,000 | 284,000,000 |
Senior note issuances | 0 | 850,000,000 | 2,300,000,000 |
Federal Financing Bank Loan | 1,200,000,000 | 0 | 0 |
Redemptions and repurchases -- | |||
Pollution control revenue bonds | -37,000,000 | -298,000,000 | -284,000,000 |
Senior notes | 0 | -1,775,000,000 | -850,000,000 |
Other long-term debt | 0 | 0 | -250,000,000 |
Payment of preferred and preference stock dividends | -17,000,000 | -17,000,000 | -17,000,000 |
Payment of common stock dividends | -954,000,000 | -907,000,000 | -983,000,000 |
Federal Financing Bank Loan Issuance Costs | -49,000,000 | -5,000,000 | -3,000,000 |
Other financing activities | -4,000,000 | -17,000,000 | -16,000,000 |
Net cash provided from (used for) financing activities | -163,000,000 | -891,000,000 | -290,000,000 |
Net Change in Cash and Cash Equivalents | -6,000,000 | -15,000,000 | 32,000,000 |
Cash and Cash Equivalents at Beginning of Year | 30,000,000 | 45,000,000 | 13,000,000 |
Cash and Cash Equivalents at End of Year | 24,000,000 | 30,000,000 | 45,000,000 |
Supplemental Cash Flow Information [Abstract] | |||
Interest paid, net of amounts capitalized | 319,000,000 | 344,000,000 | 337,000,000 |
Income taxes (net of refunds) | 507,000,000 | 298,000,000 | 312,000,000 |
Noncash transactions - accrued property additions at year-end | 154,000,000 | 208,000,000 | 261,000,000 |
Gulf Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 149,179,000 | 132,133,000 | 132,135,000 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 152,670,000 | 155,798,000 | 147,723,000 |
Deferred income taxes | 65,330,000 | 77,069,000 | 174,305,000 |
Allowance for equity funds used during construction | -12,021,000 | -6,448,000 | -5,221,000 |
Pension, postretirement, and other employee benefits | -23,305,000 | 11,422,000 | -8,109,000 |
Stock based compensation expense | 1,928,000 | 1,749,000 | 1,647,000 |
Amortization of Deferred Investment Tax Credits | -1,300,000 | -1,400,000 | -1,400,000 |
Other, net | -1,233,000 | 5,865,000 | 4,518,000 |
Changes in certain current assets and liabilities -- | |||
-Receivables | -17,178,000 | -49,051,000 | 8,713,000 |
-Fossil fuel stock | 33,603,000 | 19,468,000 | -6,144,000 |
-Materials and supplies | -721,000 | -1,570,000 | -3,035,000 |
-Prepaid income taxes | -19,179,000 | 15,526,000 | 355,000 |
-Other current assets | -883,000 | 682,000 | 417,000 |
-Accounts payable | 8,279,000 | -6,964,000 | -5,195,000 |
-Accrued taxes | -1,924,000 | -4,759,000 | -4,705,000 |
-Accrued compensation | 11,237,000 | -3,309,000 | 481,000 |
-Over recovered regulatory clause revenues | 0 | -17,092,000 | -10,858,000 |
-Other current liabilities | -2,704,000 | -782,000 | -7,837,000 |
Net cash provided from operating activities | 343,078,000 | 329,737,000 | 419,190,000 |
Investing Activities: | |||
Property additions | -348,305,000 | -292,914,000 | -313,257,000 |
Cost of removal, net of salvage | -12,932,000 | -13,827,000 | -28,993,000 |
Change in construction payables | 11,574,000 | 6,796,000 | 1,161,000 |
Payments pursuant to long-term service agreements | -8,012,000 | -7,109,000 | -8,119,000 |
Other investing activities | -19,000 | 496,000 | 656,000 |
Net cash used for investing activities | -357,694,000 | -306,558,000 | -348,552,000 |
Financing Activities: | |||
Increase (decrease) in notes payable, net | -25,900,000 | 12,108,000 | 16,075,000 |
Proceeds -- | |||
Issuance of preference stock | 0 | 50,000,000 | 0 |
Common stock issuances | 50,000,000 | 40,000,000 | 40,000,000 |
Capital contributions from parent company | 4,037,000 | 2,987,000 | 2,106,000 |
Pollution control revenue bonds issuances and remarketings | 42,075,000 | 63,000,000 | 13,000,000 |
Senior note issuances | 200,000,000 | 90,000,000 | 100,000,000 |
Redemptions and repurchases -- | |||
Pollution control revenue bonds | -29,075,000 | -76,000,000 | -13,000,000 |
Senior notes | -75,000,000 | -90,000,000 | -91,363,000 |
Payment of preferred and preference stock dividends | -9,003,000 | -7,004,000 | -6,203,000 |
Payment of common stock dividends | -123,200,000 | -115,400,000 | -115,800,000 |
Other financing activities | -2,457,000 | -3,284,000 | -614,000 |
Net cash provided from (used for) financing activities | 31,477,000 | -33,593,000 | -55,799,000 |
Net Change in Cash and Cash Equivalents | 16,861,000 | -10,414,000 | 14,839,000 |
Cash and Cash Equivalents at Beginning of Year | 21,753,000 | 32,167,000 | 17,328,000 |
Cash and Cash Equivalents at End of Year | 38,614,000 | 21,753,000 | 32,167,000 |
Supplemental Cash Flow Information [Abstract] | |||
Interest paid, net of amounts capitalized | 48,030,000 | 53,401,000 | 58,255,000 |
Income taxes (net of refunds) | 44,125,000 | -10,727,000 | -96,639,000 |
Noncash transactions - accrued property additions at year-end | 41,526,000 | 31,546,000 | 27,369,000 |
Mississippi Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | -326,948,000 | -474,892,000 | 101,675,000 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 104,422,000 | 92,465,000 | 86,981,000 |
Deferred income taxes | 145,417,000 | -396,400,000 | 17,688,000 |
Investment tax credits | -38,366,000 | 144,036,000 | 82,464,000 |
Allowance for equity funds used during construction | -136,436,000 | -121,629,000 | -64,793,000 |
Pension, postretirement, and other employee benefits | -28,899,000 | 13,953,000 | -35,425,000 |
Hedge settlements | 0 | 0 | -15,983,000 |
Stock based compensation expense | 2,903,000 | 2,510,000 | 2,084,000 |
Regulatory assets associated with Kemper IGCC | -71,816,000 | -35,220,000 | -15,445,000 |
Estimated loss on Kemper IGCC | 868,000,000 | 1,102,000,000 | 78,000,000 |
Kemper regulatory deferral | 0 | 90,524,000 | 0 |
Amortization of Deferred Investment Tax Credits | -1,400,000 | -1,200,000 | -1,200,000 |
Other, net | 14,022,000 | 14,585,000 | 10,516,000 |
Changes in certain current assets and liabilities -- | |||
-Receivables | -19,065,000 | -25,001,000 | -6,589,000 |
-Under recovered regulatory clause revenues | -2,471,000 | 0 | 0 |
-Fossil fuel stock | 13,121,000 | 63,093,000 | -36,206,000 |
-Materials and supplies | -15,496,000 | -11,087,000 | -3,473,000 |
-Prepaid income taxes | -50,457,000 | 16,644,000 | -3,852,000 |
-Other current assets | -3,940,000 | -4,363,000 | -19,851,000 |
-Accounts payable | 32,661,000 | 12,693,000 | 8,814,000 |
-Accrued taxes | 39,392,000 | 11,141,000 | 13,768,000 |
-Accrued interest | 29,349,000 | 16,768,000 | 17,627,000 |
-Accrued compensation | 17,008,000 | -6,382,000 | -183,000 |
-Over recovered regulatory clause revenues | -17,826,000 | -58,979,000 | 16,836,000 |
-Mirror CWIP | 180,255,000 | 0 | 0 |
-Other current liabilities | -446,000 | 1,109,000 | 757,000 |
Net cash provided from operating activities | 734,384,000 | 447,568,000 | 235,410,000 |
Investing Activities: | |||
Property additions | -1,257,440,000 | -1,640,782,000 | -1,620,047,000 |
Investment in restricted cash | -10,548,000 | 0 | 0 |
Distribution of restricted cash | 10,548,000 | 0 | 0 |
Cost of removal, net of salvage | -13,418,000 | -10,386,000 | -4,355,000 |
Change in construction payables | -49,532,000 | -50,000,000 | 78,961,000 |
Capital grant proceeds | 0 | 4,500,000 | 13,372,000 |
Proceeds from asset sales | 0 | 79,020,000 | 0 |
Other investing activities | -19,217,000 | 14,903,000 | -16,706,000 |
Net cash used for investing activities | -1,339,607,000 | -1,602,745,000 | -1,548,775,000 |
Proceeds -- | |||
Interest-bearing refundable deposit related to asset sale | 125,000,000 | 0 | 150,000,000 |
Capital contributions from parent company | 451,387,000 | 1,077,088,000 | 702,971,000 |
Bonds-Other | 22,866,000 | 42,342,000 | 51,471,000 |
Senior note issuances | 0 | 0 | 600,000,000 |
Other long-term debt issuances | 470,000,000 | 475,000,000 | 50,000,000 |
Redemptions and repurchases -- | |||
Bonds-Other | -34,116,000 | -82,563,000 | 0 |
Capital Leases | -2,539,000 | -697,000 | -633,000 |
Senior notes | 0 | -50,000,000 | -90,000,000 |
Other long-term debt | -220,000,000 | -125,000,000 | -115,000,000 |
Return of paid in capital | -219,720,000 | -104,804,000 | 0 |
Payment of preferred and preference stock dividends | -1,733,000 | -1,733,000 | -1,733,000 |
Payment of common stock dividends | 0 | -71,956,000 | -106,800,000 |
Other financing activities | 1,414,000 | -2,343,000 | 6,512,000 |
Net cash provided from (used for) financing activities | 592,559,000 | 1,155,334,000 | 1,246,788,000 |
Net Change in Cash and Cash Equivalents | -12,664,000 | 157,000 | -66,577,000 |
Cash and Cash Equivalents at Beginning of Year | 145,165,000 | 145,008,000 | 211,585,000 |
Cash and Cash Equivalents at End of Year | 132,501,000 | 145,165,000 | 145,008,000 |
Supplemental Cash Flow Information [Abstract] | |||
Interest paid, net of amounts capitalized | 6,992,000 | 20,285,000 | 32,589,000 |
Income taxes (net of refunds) | -379,158,000 | -134,198,000 | -77,580,000 |
Noncash transactions - accrued property additions at year-end | 114,469,000 | 164,863,000 | 214,863,000 |
Noncash transactions - capital lease obligation | 0 | 82,915,000 | 0 |
Southern Power [Member] | |||
Operating Activities: | |||
Net Income (Loss) | 175,075,000 | 165,533,000 | 175,285,000 |
Adjustments to reconcile net income to net cash provided from operating activities -- | |||
Depreciation and amortization, total | 225,234,000 | 183,239,000 | 156,268,000 |
Deferred income taxes | -168,110,000 | 171,301,000 | 228,780,000 |
Investment tax credits | 73,512,000 | 158,096,000 | 45,047,000 |
Amortization of Deferred Investment Tax Credits | -11,399,000 | -5,535,000 | -2,633,000 |
Deferred revenues | -20,860,000 | -18,477,000 | -12,633,000 |
Mark-to-market adjustments | -1,894,000 | 850,000 | -9,275,000 |
Other, net | 11,629,000 | 3,335,000 | 3,104,000 |
Changes in certain current assets and liabilities -- | |||
-Receivables | -25,596,000 | -11,178,000 | -1,384,000 |
-Fossil fuel stock | -2,576,000 | 2,438,000 | -8,578,000 |
-Materials and supplies | -3,613,000 | -8,410,000 | -7,825,000 |
-Prepaid income taxes | 35,284,000 | -29,609,000 | -3,223,000 |
-Other current assets | -1,822,000 | -2,219,000 | -1,624,000 |
-Accounts payable | 30,352,000 | -11,572,000 | 10,514,000 |
-Accrued taxes | 284,348,000 | -299,000 | 431,000 |
-Accrued interest | 1,166,000 | 6,093,000 | 385,000 |
-Other current liabilities | 1,646,000 | 777,000 | 492,000 |
Net cash provided from operating activities | 602,376,000 | 604,363,000 | 573,131,000 |
Investing Activities: | |||
Property additions | -20,566,000 | -500,756,000 | -116,633,000 |
Cash paid for acquisitions | -730,509,000 | -132,163,000 | -124,059,000 |
Change in construction payables, net of joint owner portion | -279,000 | -4,072,000 | -27,387,000 |
Payments pursuant to long-term service agreements | -60,554,000 | -57,269,000 | -63,932,000 |
Other investing activities | -1,756,000 | -1,725,000 | -446,000 |
Net cash used for investing activities | -813,664,000 | -695,985,000 | -332,457,000 |
Financing Activities: | |||
Increase (decrease) in notes payable, net | 194,917,000 | -70,968,000 | -108,552,000 |
Proceeds -- | |||
Capital contributions from parent company | 146,356,000 | 1,487,000 | -662,000 |
Senior note issuances | 0 | 300,000,000 | 0 |
Other long-term debt issuances | 10,253,000 | 23,583,000 | 5,470,000 |
Redemptions and repurchases -- | |||
Other long-term debt | -9,513,000 | -9,284,000 | -2,450,000 |
Payments to Noncontrolling Interests | -1,089,000 | -506,000 | 0 |
Proceeds from Noncontrolling Interests | 7,531,000 | 17,328,000 | 3,400,000 |
Payment of common stock dividends | -131,120,000 | -129,120,000 | -127,000,000 |
Other financing activities | -185,000 | -746,000 | 769,000 |
Net cash provided from (used for) financing activities | 217,150,000 | 131,774,000 | -229,025,000 |
Net Change in Cash and Cash Equivalents | 5,862,000 | 40,152,000 | 11,649,000 |
Cash and Cash Equivalents at Beginning of Year | 68,744,000 | 28,592,000 | 16,943,000 |
Cash and Cash Equivalents at End of Year | 74,606,000 | 68,744,000 | 28,592,000 |
Supplemental Cash Flow Information [Abstract] | |||
Interest paid, net of amounts capitalized | 85,168,000 | 60,396,000 | 50,248,000 |
Income taxes (net of refunds) | -219,641,000 | -226,179,000 | -175,269,000 |
Noncash transactions - accrued property additions at year-end | 852,000 | 5,567,000 | 11,203,000 |
Acquisitions | 228,964,000 | 0 | 0 |
Capital contributions from noncontrolling interests | $220,734,000 | $0 | $0 |
Consolidated_Statements_of_Cas1
Consolidated Statements of Cash Flows (Parenthetical) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Net cash paid for capitalized interest | $111,000 | $92,000 | $83,000 |
Alabama Power [Member] | |||
Net cash paid for capitalized interest | 18,000 | 11,000 | 7,000 |
Georgia Power [Member] | |||
Net cash paid for capitalized interest | 18,000 | 14,000 | 21,000 |
Gulf Power [Member] | |||
Net cash paid for capitalized interest | 5,373 | 3,421 | 2,500 |
Mississippi Power [Member] | |||
Net cash paid for capitalized interest | 68,679 | 54,118 | 32,816 |
Southern Power [Member] | |||
Net cash paid for capitalized interest | ($113) | $9,178 | $19,092 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Current Assets: | ||
Cash and cash equivalents | $710,000,000 | $659,000,000 |
Receivables -- | ||
Customer accounts receivable | 1,090,000,000 | 1,027,000,000 |
Unbilled revenues | 432,000,000 | 448,000,000 |
Under recovered regulatory clause revenues | 136,000,000 | 58,000,000 |
Other accounts and notes receivable | 307,000,000 | 304,000,000 |
Accumulated provision for uncollectible accounts | -18,000,000 | -18,000,000 |
Fossil fuel stock, at average cost | 930,000,000 | 1,339,000,000 |
Materials and supplies, at average cost | 1,039,000,000 | 959,000,000 |
Vacation pay | 177,000,000 | 171,000,000 |
Deferred income taxes, current | 506,000,000 | 143,000,000 |
Prepaid expenses | 665,000,000 | 278,000,000 |
Other regulatory assets, current | 346,000,000 | 207,000,000 |
Other current assets | 50,000,000 | 39,000,000 |
Total current assets | 6,370,000,000 | 5,614,000,000 |
Property, Plant, and Equipment: | ||
In service | 70,013,000,000 | 66,021,000,000 |
Less accumulated depreciation | 24,059,000,000 | 23,059,000,000 |
Plant in service, net of depreciation | 45,954,000,000 | 42,962,000,000 |
Other utility plant, net | 211,000,000 | 240,000,000 |
Nuclear fuel, at amortized cost | 911,000,000 | 855,000,000 |
Construction work in progress | 7,792,000,000 | 7,151,000,000 |
Total property, plant, and equipment | 54,868,000,000 | 51,208,000,000 |
Other Property and Investments: | ||
Nuclear decommissioning trusts, at fair value | 1,546,000,000 | 1,465,000,000 |
Leveraged leases | 743,000,000 | 665,000,000 |
Miscellaneous property and investments | 203,000,000 | 218,000,000 |
Total other property and investments | 2,492,000,000 | 2,348,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 1,510,000,000 | 1,436,000,000 |
Prepaid pension costs | 0 | 419,000,000 |
Unamortized debt issuance expense | 202,000,000 | 139,000,000 |
Unamortized loss on reacquired debt | 243,000,000 | 269,000,000 |
Other regulatory assets, deferred | 4,334,000,000 | 2,495,000,000 |
Other deferred charges and assets | 904,000,000 | 618,000,000 |
Total deferred charges and other assets | 7,193,000,000 | 5,376,000,000 |
Total Assets | 70,923,000,000 | 64,546,000,000 |
Current Liabilities: | ||
Securities due within one year | 3,333,000,000 | 469,000,000 |
Interest-bearing refundable deposit related to asset sale | 275,000,000 | 150,000,000 |
Notes payable | 803,000,000 | 1,482,000,000 |
Accounts payable | 1,593,000,000 | 1,376,000,000 |
Customer deposits | 390,000,000 | 380,000,000 |
Accrued taxes -- | ||
Accrued income taxes | 151,000,000 | 13,000,000 |
Other accrued taxes | 487,000,000 | 456,000,000 |
Accrued interest | 295,000,000 | 251,000,000 |
Accrued vacation pay | 223,000,000 | 217,000,000 |
Accrued compensation | 576,000,000 | 303,000,000 |
Other regulatory liabilities, current | 26,000,000 | 82,000,000 |
Mirror Construction Work In Progress Balance | 271,000,000 | 0 |
Other current liabilities | 544,000,000 | 346,000,000 |
Total current liabilities | 8,967,000,000 | 5,525,000,000 |
Senior notes - | ||
Unamortized debt premium | 69,000,000 | 79,000,000 |
Unamortized debt discount | -33,000,000 | -30,000,000 |
Long-term Debt | 20,841,000,000 | 21,344,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 11,568,000,000 | 10,563,000,000 |
Deferred credits related to income taxes | 192,000,000 | 203,000,000 |
Accumulated deferred investment tax credits | 1,208,000,000 | 966,000,000 |
Employee benefit obligations | 2,432,000,000 | 1,461,000,000 |
Asset retirement obligations | 2,168,000,000 | 2,006,000,000 |
Other cost of removal obligations | 1,215,000,000 | 1,275,000,000 |
Other regulatory liabilities, deferred | 398,000,000 | 479,000,000 |
Other deferred credits and liabilities | 594,000,000 | 585,000,000 |
Total deferred credits and other liabilities | 19,775,000,000 | 17,538,000,000 |
Total Liabilities | 49,583,000,000 | 44,407,000,000 |
Redeemable Preferred Stock of Subsidiaries | 375,000,000 | 375,000,000 |
Redeemable Noncontrolling Interest, Equity, Carrying Amount | 39,000,000 | 0 |
Common Stockholders' Equity: | ||
Common stock | 4,539,000,000 | 4,461,000,000 |
Paid-in capital | 5,955,000,000 | 5,362,000,000 |
Retained earnings | 9,609,000,000 | 9,510,000,000 |
Accumulated other comprehensive loss | -128,000,000 | -75,000,000 |
Total Common Stockholders' Equity | 19,949,000,000 | 19,008,000,000 |
Stockholders' Equity Attributable to Noncontrolling Interest | 977,000,000 | 756,000,000 |
Total stockholders' equity | 20,926,000,000 | 19,764,000,000 |
Total Liabilities and Stockholders' Equity | 70,923,000,000 | 64,546,000,000 |
Commitments and Contingent Matters | ||
Alabama Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | 273,000,000 | 295,000,000 |
Receivables -- | ||
Customer accounts receivable | 345,000,000 | 341,000,000 |
Unbilled revenues | 138,000,000 | 142,000,000 |
Under recovered regulatory clause revenues | 74,000,000 | 0 |
Other accounts and notes receivable | 23,000,000 | 30,000,000 |
Affiliated companies | 37,000,000 | 54,000,000 |
Accumulated provision for uncollectible accounts | -9,000,000 | -8,000,000 |
Fossil fuel stock, at average cost | 268,000,000 | 329,000,000 |
Materials and supplies, at average cost | 406,000,000 | 375,000,000 |
Vacation pay | 65,000,000 | 63,000,000 |
Prepaid expenses | 244,000,000 | 57,000,000 |
Other regulatory assets, current | 84,000,000 | 54,000,000 |
Other current assets | 5,000,000 | 6,000,000 |
Total current assets | 1,953,000,000 | 1,738,000,000 |
Property, Plant, and Equipment: | ||
In service | 23,080,000,000 | 22,092,000,000 |
Less accumulated depreciation | 8,522,000,000 | 8,114,000,000 |
Plant in service, net of depreciation | 14,558,000,000 | 13,978,000,000 |
Nuclear fuel, at amortized cost | 348,000,000 | 332,000,000 |
Construction work in progress | 1,006,000,000 | 748,000,000 |
Total property, plant, and equipment | 15,912,000,000 | 15,058,000,000 |
Other Property and Investments: | ||
Equity investments in unconsolidated subsidiaries | 66,000,000 | 54,000,000 |
Nuclear decommissioning trusts, at fair value | 756,000,000 | 714,000,000 |
Miscellaneous property and investments | 84,000,000 | 80,000,000 |
Total other property and investments | 906,000,000 | 848,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 525,000,000 | 519,000,000 |
Prepaid pension costs | 0 | 276,000,000 |
Deferred under recovered regulatory clause revenues | 31,000,000 | 25,000,000 |
Other regulatory assets, deferred | 1,063,000,000 | 645,000,000 |
Other deferred charges and assets | 162,000,000 | 142,000,000 |
Total deferred charges and other assets | 1,781,000,000 | 1,607,000,000 |
Total Assets | 20,552,000,000 | 19,251,000,000 |
Current Liabilities: | ||
Securities due within one year | 454,000,000 | 0 |
Affiliated | 248,000,000 | 198,000,000 |
Accounts payable | 443,000,000 | 339,000,000 |
Customer deposits | 87,000,000 | 85,000,000 |
Accrued taxes -- | ||
Accrued income taxes | 2,000,000 | 11,000,000 |
Other accrued taxes | 37,000,000 | 33,000,000 |
Accrued interest | 66,000,000 | 61,000,000 |
Accrued vacation pay | 54,000,000 | 53,000,000 |
Accrued compensation | 131,000,000 | 74,000,000 |
Other regulatory liabilities, current | 2,000,000 | 37,000,000 |
Other current liabilities | 80,000,000 | 41,000,000 |
Total current liabilities | 1,604,000,000 | 932,000,000 |
Senior notes - | ||
Long-term Debt | 6,176,000,000 | 6,233,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 3,874,000,000 | 3,603,000,000 |
Deferred credits related to income taxes | 72,000,000 | 75,000,000 |
Accumulated deferred investment tax credits | 125,000,000 | 133,000,000 |
Employee benefit obligations | 326,000,000 | 195,000,000 |
Asset retirement obligations | 829,000,000 | 730,000,000 |
Other cost of removal obligations | 744,000,000 | 828,000,000 |
Other regulatory liabilities, deferred | 239,000,000 | 259,000,000 |
Deferred over recovered regulatory clause revenues | 47,000,000 | 15,000,000 |
Other deferred credits and liabilities | 79,000,000 | 61,000,000 |
Total deferred credits and other liabilities | 6,335,000,000 | 5,899,000,000 |
Total Liabilities | 14,115,000,000 | 13,064,000,000 |
Redeemable Preferred Stock of Subsidiaries | 342,000,000 | 342,000,000 |
Redeemable Preferred Stock | 342,000,000 | 342,000,000 |
Preference Stock | 343,000,000 | 343,000,000 |
Common Stockholders' Equity: | ||
Common stock | 1,222,000,000 | 1,222,000,000 |
Paid-in capital | 2,304,000,000 | 2,262,000,000 |
Retained earnings | 2,255,000,000 | 2,044,000,000 |
Accumulated other comprehensive loss | -29,000,000 | -26,000,000 |
Total Common Stockholders' Equity | 5,752,000,000 | 5,502,000,000 |
Total stockholders' equity | 5,752,000,000 | 5,502,000,000 |
Total Liabilities and Stockholders' Equity | 20,552,000,000 | 19,251,000,000 |
Commitments and Contingent Matters | ||
Georgia Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | 24,000,000 | 30,000,000 |
Receivables -- | ||
Customer accounts receivable | 553,000,000 | 512,000,000 |
Unbilled revenues | 201,000,000 | 209,000,000 |
Joint owner accounts receivable | 121,000,000 | 67,000,000 |
Other accounts and notes receivable | 61,000,000 | 117,000,000 |
Affiliated companies | 18,000,000 | 21,000,000 |
Accumulated provision for uncollectible accounts | -6,000,000 | -5,000,000 |
Fossil fuel stock, at average cost | 439,000,000 | 742,000,000 |
Materials and supplies, at average cost | 438,000,000 | 409,000,000 |
Vacation pay | 91,000,000 | 88,000,000 |
Prepaid income taxes | 278,000,000 | 97,000,000 |
Other regulatory assets, current | 136,000,000 | 106,000,000 |
Other current assets | 74,000,000 | 53,000,000 |
Total current assets | 2,428,000,000 | 2,446,000,000 |
Property, Plant, and Equipment: | ||
In service | 31,083,000,000 | 30,132,000,000 |
Less accumulated depreciation | 11,222,000,000 | 10,970,000,000 |
Plant in service, net of depreciation | 19,861,000,000 | 19,162,000,000 |
Other utility plant, net | 211,000,000 | 240,000,000 |
Nuclear fuel, at amortized cost | 563,000,000 | 523,000,000 |
Construction work in progress | 4,031,000,000 | 3,500,000,000 |
Total property, plant, and equipment | 24,666,000,000 | 23,425,000,000 |
Other Property and Investments: | ||
Equity investments in unconsolidated subsidiaries | 58,000,000 | 46,000,000 |
Nuclear decommissioning trusts, at fair value | 789,000,000 | 751,000,000 |
Miscellaneous property and investments | 38,000,000 | 44,000,000 |
Total other property and investments | 885,000,000 | 841,000,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 698,000,000 | 718,000,000 |
Prepaid pension costs | 0 | 118,000,000 |
Deferred under recovered regulatory clause revenues | 197,000,000 | 0 |
Other regulatory assets, deferred | 1,753,000,000 | 1,113,000,000 |
Other deferred charges and assets | 403,000,000 | 246,000,000 |
Total deferred charges and other assets | 3,051,000,000 | 2,195,000,000 |
Total Assets | 31,030,000,000 | 28,907,000,000 |
Current Liabilities: | ||
Securities due within one year | 1,154,000,000 | 5,000,000 |
Notes payable | 156,000,000 | 1,047,000,000 |
Affiliated | 451,000,000 | 417,000,000 |
Accounts payable | 555,000,000 | 472,000,000 |
Customer deposits | 253,000,000 | 246,000,000 |
Accrued taxes -- | ||
Other accrued taxes | 332,000,000 | 321,000,000 |
Accrued interest | 96,000,000 | 91,000,000 |
Accrued vacation pay | 63,000,000 | 61,000,000 |
Accrued compensation | 153,000,000 | 80,000,000 |
Liabilities from risk management activities | 32,000,000 | 13,000,000 |
Other regulatory liabilities, current | 21,000,000 | 17,000,000 |
Over recovered regulatory clause revenues, current | 0 | 14,000,000 |
Other current liabilities | 204,000,000 | 122,000,000 |
Total current liabilities | 3,470,000,000 | 2,906,000,000 |
Senior notes - | ||
Long-term Debt | 8,683,000,000 | 8,633,000,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 5,507,000,000 | 5,200,000,000 |
Deferred credits related to income taxes | 106,000,000 | 112,000,000 |
Accumulated deferred investment tax credits | 196,000,000 | 203,000,000 |
Employee benefit obligations | 903,000,000 | 542,000,000 |
Deferred capacity expense | 167,000,000 | 162,000,000 |
Asset retirement obligations | 1,223,000,000 | 1,210,000,000 |
Other cost of removal obligations | 46,000,000 | 43,000,000 |
Other deferred credits and liabilities | 209,000,000 | 201,000,000 |
Total deferred credits and other liabilities | 8,190,000,000 | 7,511,000,000 |
Total Liabilities | 20,343,000,000 | 19,050,000,000 |
Redeemable Preferred Stock | 45,000,000 | 45,000,000 |
Preference Stock | 221,000,000 | 221,000,000 |
Common Stockholders' Equity: | ||
Common stock | 398,000,000 | 398,000,000 |
Paid-in capital | 6,196,000,000 | 5,633,000,000 |
Retained earnings | 3,835,000,000 | 3,565,000,000 |
Accumulated other comprehensive loss | -8,000,000 | -5,000,000 |
Total Common Stockholders' Equity | 10,421,000,000 | 9,591,000,000 |
Total stockholders' equity | 10,421,000,000 | 9,591,000,000 |
Total Liabilities and Stockholders' Equity | 31,030,000,000 | 28,907,000,000 |
Commitments and Contingent Matters | ||
Gulf Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | 38,614,000 | 21,753,000 |
Receivables -- | ||
Customer accounts receivable | 73,000,000 | 64,884,000 |
Unbilled revenues | 58,268,000 | 57,282,000 |
Under recovered regulatory clause revenues | 57,153,000 | 48,282,000 |
Other accounts and notes receivable | 8,145,000 | 8,620,000 |
Affiliated companies | 9,867,000 | 8,259,000 |
Accumulated provision for uncollectible accounts | -2,087,000 | -1,131,000 |
Fossil fuel stock, at average cost | 101,447,000 | 135,050,000 |
Materials and supplies, at average cost | 55,656,000 | 54,935,000 |
Prepaid expenses | 39,673,000 | 33,186,000 |
Other regulatory assets, current | 74,242,000 | 18,536,000 |
Other current assets | 1,711,000 | 6,120,000 |
Total current assets | 515,689,000 | 455,776,000 |
Property, Plant, and Equipment: | ||
In service | 4,494,953,000 | 4,363,664,000 |
Less accumulated depreciation | 1,295,714,000 | 1,211,336,000 |
Plant in service, net of depreciation | 3,199,239,000 | 3,152,328,000 |
Construction work in progress | 465,033,000 | 280,626,000 |
Total property, plant, and equipment | 3,664,272,000 | 3,432,954,000 |
Other Property and Investments: | ||
Total other property and investments | 15,148,000 | 15,314,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 55,931,000 | 50,597,000 |
Prepaid pension costs | 0 | 11,533,000 |
Other regulatory assets, deferred | 416,028,000 | 340,415,000 |
Other deferred charges and assets | 41,191,000 | 30,982,000 |
Total deferred charges and other assets | 513,150,000 | 433,527,000 |
Total Assets | 4,708,259,000 | 4,337,571,000 |
Current Liabilities: | ||
Securities due within one year | 0 | 75,000,000 |
Notes payable | 109,977,000 | 135,878,000 |
Affiliated | 87,397,000 | 76,897,000 |
Accounts payable | 55,848,000 | 47,038,000 |
Customer deposits | 35,094,000 | 34,433,000 |
Accrued taxes -- | ||
Accrued income taxes | 46,000 | 45,000 |
Other accrued taxes | 9,201,000 | 7,486,000 |
Accrued interest | 10,686,000 | 10,272,000 |
Accrued compensation | 22,894,000 | 11,657,000 |
Deferred Capacity Expense, Other | 21,988,000 | 0 |
Liabilities from risk management activities | 36,934,000 | 6,470,000 |
Other regulatory liabilities, current | 566,000 | 13,408,000 |
Other current liabilities | 22,386,000 | 22,972,000 |
Total current liabilities | 413,017,000 | 441,556,000 |
Senior notes - | ||
Long-term Debt | 1,369,594,000 | 1,158,163,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 799,723,000 | 734,355,000 |
Accumulated deferred investment tax credits | 2,783,000 | 4,055,000 |
Employee benefit obligations | 120,752,000 | 76,338,000 |
Deferred capacity expense | 163,077,000 | 180,149,000 |
Other cost of removal obligations | 234,587,000 | 228,148,000 |
Other regulatory liabilities, deferred | 48,556,000 | 56,051,000 |
Other deferred credits and liabilities | 100,076,000 | 77,126,000 |
Total deferred credits and other liabilities | 1,469,554,000 | 1,356,222,000 |
Total Liabilities | 3,252,165,000 | 2,955,941,000 |
Preference Stock | 146,504,000 | 146,504,000 |
Common Stockholders' Equity: | ||
Common stock | 483,060,000 | 433,060,000 |
Paid-in capital | 559,797,000 | 552,681,000 |
Retained earnings | 267,470,000 | 250,494,000 |
Accumulated other comprehensive loss | -737,000 | -1,109,000 |
Total Common Stockholders' Equity | 1,309,590,000 | 1,235,126,000 |
Total stockholders' equity | 1,309,590,000 | 1,235,126,000 |
Total Liabilities and Stockholders' Equity | 4,708,259,000 | 4,337,571,000 |
Commitments and Contingent Matters | ||
Mississippi Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | 132,501,000 | 145,165,000 |
Receivables -- | ||
Customer accounts receivable | 40,648,000 | 40,978,000 |
Unbilled revenues | 35,494,000 | 38,895,000 |
Under recovered regulatory clause revenues | 2,471,000 | 0 |
Other accounts and notes receivable | 11,256,000 | 4,600,000 |
Affiliated companies | 51,060,000 | 34,920,000 |
Accumulated provision for uncollectible accounts | -825,000 | -3,018,000 |
Fossil fuel stock, at average cost | 100,164,000 | 113,285,000 |
Materials and supplies, at average cost | 61,582,000 | 45,347,000 |
Prepaid income taxes | 190,631,000 | 34,751,000 |
Other regulatory assets, current | 72,840,000 | 48,583,000 |
Other current assets | 6,209,000 | 9,357,000 |
Total current assets | 704,031,000 | 512,863,000 |
Property, Plant, and Equipment: | ||
In service | 4,378,087,000 | 3,458,770,000 |
Less accumulated depreciation | 1,172,715,000 | 1,095,352,000 |
Plant in service, net of depreciation | 3,205,372,000 | 2,363,418,000 |
Construction work in progress | 2,160,646,000 | 2,586,031,000 |
Total property, plant, and equipment | 5,366,018,000 | 4,949,449,000 |
Other Property and Investments: | ||
Total other property and investments | 5,498,000 | 4,857,000 |
Deferred Charges and Other Assets: | ||
Deferred charges related to income taxes | 225,507,000 | 143,747,000 |
Other regulatory assets, deferred | 385,410,000 | 200,620,000 |
Deferred Tax Assets, Net, Noncurrent | 17,388,000 | 0 |
Other deferred charges and assets | 52,876,000 | 36,673,000 |
Total deferred charges and other assets | 681,181,000 | 381,040,000 |
Total Assets | 6,756,728,000 | 5,848,209,000 |
Current Liabilities: | ||
Securities due within one year | 777,667,000 | 13,789,000 |
Interest-bearing refundable deposit related to asset sale | 275,000,000 | 150,000,000 |
Affiliated | 85,882,000 | 70,299,000 |
Accounts payable | 177,736,000 | 210,191,000 |
Customer deposits | 14,970,000 | 14,379,000 |
Accrued taxes -- | ||
Accrued income taxes | 142,461,000 | 5,590,000 |
Other accrued taxes | 83,686,000 | 77,958,000 |
Accrued interest | 76,494,000 | 47,144,000 |
Accrued compensation | 26,331,000 | 9,324,000 |
Other regulatory liabilities, current | 2,164,000 | 14,480,000 |
Mirror Construction Work In Progress Balance | 270,779,000 | 0 |
Over recovered regulatory clause liabilities | 532,000 | 18,358,000 |
Other current liabilities | 44,701,000 | 21,413,000 |
Total current liabilities | 1,978,403,000 | 652,925,000 |
Senior notes - | ||
Unamortized debt premium | 62,701,000 | 71,807,000 |
Unamortized debt discount | -1,921,000 | -2,113,000 |
Long-term Debt | 1,630,487,000 | 2,167,067,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 284,849,000 | 72,808,000 |
Deferred credits related to income taxes | 9,370,000 | 10,191,000 |
Accumulated deferred investment tax credits | 282,816,000 | 284,248,000 |
Employee benefit obligations | 147,536,000 | 94,430,000 |
Asset retirement obligations | 48,248,000 | 41,197,000 |
Other cost of removal obligations | 165,999,000 | 156,683,000 |
Other regulatory liabilities, deferred | 63,681,000 | 144,992,000 |
Other deferred credits and liabilities | 28,299,000 | 14,337,000 |
Total deferred credits and other liabilities | 1,030,798,000 | 818,886,000 |
Total Liabilities | 4,639,688,000 | 3,638,878,000 |
Redeemable Preferred Stock | 32,780,000 | 32,780,000 |
Common Stockholders' Equity: | ||
Common stock | 37,691,000 | 37,691,000 |
Paid-in capital | 2,612,136,000 | 2,376,595,000 |
Retained earnings | -558,552,000 | -229,871,000 |
Accumulated other comprehensive loss | -7,015,000 | -7,864,000 |
Total Common Stockholders' Equity | 2,084,260,000 | 2,176,551,000 |
Total stockholders' equity | 2,084,260,000 | 2,176,551,000 |
Total Liabilities and Stockholders' Equity | 6,756,728,000 | 5,848,209,000 |
Commitments and Contingent Matters | ||
Southern Power [Member] | ||
Current Assets: | ||
Cash and cash equivalents | 74,606,000 | 68,744,000 |
Receivables -- | ||
Customer accounts receivable | 76,608,000 | 73,497,000 |
Other accounts and notes receivable | 14,707,000 | 3,983,000 |
Affiliated companies | 34,223,000 | 38,391,000 |
Fossil fuel stock, at average cost | 21,755,000 | 19,178,000 |
Materials and supplies, at average cost | 57,843,000 | 54,780,000 |
Prepaid income taxes | 19,239,000 | 54,523,000 |
Deferred income taxes, current | 305,814,000 | 209,000 |
Prepaid expenses | 17,301,000 | 20,946,000 |
Assets from risk management activities | 5,297,000 | 182,000 |
Total current assets | 627,393,000 | 334,433,000 |
Property, Plant, and Equipment: | ||
In service | 5,656,974,000 | 4,696,134,000 |
Less accumulated depreciation | 1,034,610,000 | 871,963,000 |
Plant in service, net of depreciation | 4,622,364,000 | 3,824,171,000 |
Construction work in progress | 10,511,000 | 9,843,000 |
Total property, plant, and equipment | 4,632,875,000 | 3,834,014,000 |
Other Property and Investments: | ||
Goodwill | 1,839,000 | 1,839,000 |
Other intangible assets, net of amortization | 47,091,000 | 43,505,000 |
Total other property and investments | 48,930,000 | 45,344,000 |
Deferred Charges and Other Assets: | ||
Prepaid long-term service agreements | 123,573,000 | 141,851,000 |
Other deferred charges and assets -- affiliated | 5,492,000 | 4,605,000 |
Other deferred charges and assets | 111,239,000 | 68,853,000 |
Total deferred charges and other assets | 240,304,000 | 215,309,000 |
Total Assets | 5,549,502,000 | 4,429,100,000 |
Current Liabilities: | ||
Securities due within one year | 525,295,000 | 599,000 |
Notes payable | 194,917,000 | 0 |
Affiliated | 78,279,000 | 56,661,000 |
Accounts payable | 30,037,000 | 20,747,000 |
Accrued taxes -- | ||
Accrued income taxes | 71,700,000 | 161,000 |
Other accrued taxes | 2,983,000 | 2,662,000 |
Accrued interest | 29,518,000 | 28,352,000 |
Other current liabilities | 14,761,000 | 18,492,000 |
Total current liabilities | 947,490,000 | 127,674,000 |
Senior notes - | ||
Unamortized debt premium | 2,378,000 | 2,467,000 |
Unamortized debt discount | -813,000 | -1,013,000 |
Long-term Debt | 1,095,340,000 | 1,619,241,000 |
Deferred Credits and Other Liabilities: | ||
Accumulated deferred income taxes | 862,795,000 | 724,390,000 |
Deferred convertible investment tax credits | 600,519,000 | 340,269,000 |
Deferred capacity revenues -- affiliated | 15,279,000 | 15,279,000 |
Other deferred credits and liabilities -- affiliated | 604,000 | 1,621,000 |
Other deferred credits and liabilities | 16,890,000 | 7,896,000 |
Total deferred credits and other liabilities | 1,496,087,000 | 1,089,455,000 |
Total Liabilities | 3,538,917,000 | 2,836,370,000 |
Redeemable Noncontrolling Interest | 39,241,000 | 28,778,000 |
Common Stockholders' Equity: | ||
Common stock | 0 | 0 |
Paid-in capital | 1,175,392,000 | 1,029,035,000 |
Retained earnings | 573,178,000 | 531,998,000 |
Accumulated other comprehensive loss | 3,286,000 | 2,919,000 |
Total Common Stockholders' Equity | 1,751,856,000 | 1,563,952,000 |
Stockholders' Equity Attributable to Noncontrolling Interest | 219,488,000 | 0 |
Total stockholders' equity | 1,971,344,000 | 1,563,952,000 |
Total Liabilities and Stockholders' Equity | 5,549,502,000 | 4,429,100,000 |
Commitments and Contingent Matters | ||
Southern Power [Member] | 4.875% due 2015 | ||
Senior notes - | ||
Senior notes | 0 | 525,000,000 |
Southern Power [Member] | 6.375% due 2036 | ||
Senior notes - | ||
Senior notes | 200,000,000 | 200,000,000 |
Southern Power [Member] | 5.15% due 2041 | ||
Senior notes - | ||
Senior notes | 575,000,000 | 575,000,000 |
Southern Power [Member] | 5.25% due 2043 | ||
Senior notes - | ||
Senior notes | 300,000,000 | 300,000,000 |
Southern Power [Member] | 3.25% due 2032-2034 | ||
Senior notes - | ||
Other long-term notes (3.25% due 2032-2034) | $18,775,000 | $17,787,000 |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, except Share data, unless otherwise specified | ||
Common stock, par value per share (in dollars per share) | $5 | $5 |
Common stock, shares authorized | 1,500,000,000 | 1,500,000,000 |
Southern Power [Member] | ||
Amortization expense on other intangible assets | $8,279 | $5,614 |
Common stock, par value per share (in dollars per share) | $0.01 | $0.01 |
Common stock, shares authorized | 1,000,000 | 1,000,000 |
Common stock, shares outstanding | 1,000 | 1,000 |
Southern Power [Member] | 4.875% due 2015 | ||
Fixed stated interest rate of debt obligation | 0.00% | 4.88% |
Southern Power [Member] | 6.375% due 2036 | ||
Fixed stated interest rate of debt obligation | 6.38% | 6.38% |
Southern Power [Member] | 5.15% due 2041 | ||
Fixed stated interest rate of debt obligation | 5.15% | 5.15% |
Southern Power [Member] | 5.25% due 2043 | ||
Fixed stated interest rate of debt obligation | 5.25% | 5.25% |
Southern Power [Member] | 3.25% due 2032-2034 | ||
Fixed stated interest rate of debt obligation | 3.25% | 3.25% |
Consolidated_Statements_of_Cap
Consolidated Statements of Capitalization (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Maturity | ||
Total long term debt payable to affiliated trusts | $206,000,000 | $206,000,000 |
Long Term Debt Maturities Repayments of Principal in Last Twelve Months | 0 | 428,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 2,375,000,000 | 2,375,000,000 |
Long-term debt maturities, 2016 | 1,360,000,000 | 1,360,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 1,495,000,000 | 1,095,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 850,000,000 | 850,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Five | 1,175,000,000 | 825,000,000 |
Long-term debt maturities, thereafter | 10,574,000,000 | 9,973,000,000 |
Long-term senior notes and debt: | ||
Total long -term senior notes and debt | 19,054,000,000 | 17,892,000,000 |
Pollution control revenue bonds -- | ||
Total other long -term debt | 4,719,000,000 | 3,503,000,000 |
Capitalized lease obligations | 159,000,000 | 163,000,000 |
Unamortized debt premium (related to plant acquisition) | 69,000,000 | 79,000,000 |
Unamortized debt discount | -33,000,000 | -30,000,000 |
Total long-term debt (annual interest requirement ) | 24,174,000,000 | 21,813,000,000 |
Less amount due within one year | 3,333,000,000 | 469,000,000 |
Long-term debt excluding amount due within one year | 20,841,000,000 | 21,344,000,000 |
Percent capitalization | 49.40% | 51.50% |
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | 375,000,000 | 375,000,000 |
Total redeemable preferred stock - percent capitalization | 0.90% | 0.90% |
Preferred and preference stock of subsidiaries | 977,000,000 | 756,000,000 |
Total preferred and preference stock of subsidiaries - percent capitalization | 2.30% | 1.80% |
Redeemable Noncontrolling Interest, Equity, Carrying Amount | 39,000,000 | 0 |
Redeemable Noncontrolling Interest As Percent Of Capitalization | 0.10% | 0.00% |
Common Stockholders' Equity: | ||
Common stock | 4,539,000,000 | 4,461,000,000 |
Paid-in capital | 5,955,000,000 | 5,362,000,000 |
Treasury, at cost | -26,000,000 | -250,000,000 |
Retained earnings | 9,609,000,000 | 9,510,000,000 |
Accumulated other comprehensive loss | -128,000,000 | -75,000,000 |
Total Common Stockholders' Equity | 19,949,000,000 | 19,008,000,000 |
Total common stockholders' equity - percent capitalization | 47.30% | 45.80% |
Total stockholders' equity | 20,926,000,000 | 19,764,000,000 |
Total Capitalization | 42,181,000,000 | 41,483,000,000 |
Percent Capitalization | 100.00% | 100.00% |
Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | 81,000,000 | 81,000,000 |
Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | 294,000,000 | 294,000,000 |
Noncumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 45,000,000 | 45,000,000 |
Preference Stock, $1 par value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 343,000,000 | 343,000,000 |
Preference Stock , $100 par or stated value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 368,000,000 | 368,000,000 |
Noncontrolling Interest [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred and preference stock of subsidiaries | 221,000,000 | 0 |
Adjustable Rate Loans [Member] | ||
Maturity | ||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 0 | 11,000,000 |
Long-term debt maturities, 2016 | 775,000,000 | 525,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 450,000,000 | 450,000,000 |
Affiliate trusts, variable rate, due 2042 [Member] | ||
Maturity | ||
Total long term debt payable to affiliated trusts | 206,000,000 | 206,000,000 |
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 3.36% | |
Pollution control revenue bonds due 2019 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 25,000,000 | 25,000,000 |
Pollution control revenue bonds due 2022 through 2049 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,466,000,000 | 1,453,000,000 |
Pollution control revenue bonds variable rate, Due 2015 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 152,000,000 | 54,000,000 |
Pollution control revenue bonds variable rate, Due 2016 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 4,000,000 | 4,000,000 |
Pollution control revenue bonds variable rate, Due 2017 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 36,000,000 | 36,000,000 |
Pollution control revenue bonds variable rate, Due 2018 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 0 | 19,000,000 |
Plant Daniel revenue bonds due 2021 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
Pollution control revenue bonds -- | ||
Taxable Revenue Bonds | 270,000,000 | 270,000,000 |
Pollution control revenue bonds variable rate, Due 2020 to 2052 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,566,000,000 | 1,642,000,000 |
Loan For Federal Financing Bank | 1,200,000,000 | 0 |
Alabama Power [Member] | ||
Maturity | ||
Total long term debt payable to affiliated trusts | 206,000,000 | 206,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 400,000,000 | 400,000,000 |
Long-term debt maturities, 2016 | 200,000,000 | 200,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 525,000,000 | 525,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Five | 200,000,000 | 200,000,000 |
Long-term debt maturities, thereafter | 3,950,000,000 | 3,550,000,000 |
Long-term senior notes and debt: | ||
Total long-term notes payable | 5,275,000,000 | 4,875,000,000 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,200,000,000 | 1,200,000,000 |
Total other long -term debt | 1,151,000,000 | 1,151,000,000 |
Capitalized lease obligations | 5,000,000 | 5,000,000 |
Unamortized debt (discount), net | -7,000,000 | -4,000,000 |
Total long-term debt (annual interest requirement ) | 6,630,000,000 | 6,233,000,000 |
Less amount due within one year | 454,000,000 | 0 |
Long-term debt excluding amount due within one year | 6,176,000,000 | 6,233,000,000 |
Percent capitalization | 49.00% | 50.20% |
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | 342,000,000 | 342,000,000 |
Total redeemable preferred stock - percent capitalization | 2.70% | 2.70% |
Preference stock | 343,000,000 | 343,000,000 |
Preferred stock | 342,000,000 | 342,000,000 |
Total preferred and preference stock of subsidiaries - percent capitalization | 2.70% | 2.80% |
Common Stockholders' Equity: | ||
Common stock | 1,222,000,000 | 1,222,000,000 |
Paid-in capital | 2,304,000,000 | 2,262,000,000 |
Retained earnings | 2,255,000,000 | 2,044,000,000 |
Accumulated other comprehensive loss | -29,000,000 | -26,000,000 |
Total Common Stockholders' Equity | 5,752,000,000 | 5,502,000,000 |
Total common stockholders' equity - percent capitalization | 45.60% | 44.30% |
Total stockholders' equity | 5,752,000,000 | 5,502,000,000 |
Total Capitalization | 12,613,000,000 | 12,420,000,000 |
Percent Capitalization | 100.00% | 100.00% |
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | 48,000,000 | 48,000,000 |
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Redeemable preferred stock | 294,000,000 | 294,000,000 |
Alabama Power [Member] | Affiliate trusts, variable rate, due 2042 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 3.36% | |
Alabama Power [Member] | Pollution control revenue bonds due 2034 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 367,000,000 | 367,000,000 |
Alabama Power [Member] | Pollution control revenue bonds due 2015 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.03% | |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 54,000,000 | 54,000,000 |
Alabama Power [Member] | Pollution control revenue bonds variable rate, Due 2017 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 36,000,000 | 36,000,000 |
Alabama Power [Member] | Pollution control revenue bonds due 2021-2038 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 694,000,000 | 694,000,000 |
Georgia Power [Member] | ||
Maturity | ||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 1,050,000,000 | 1,050,000,000 |
Long-term debt maturities, 2016 | 250,000,000 | 250,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 450,000,000 | 450,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 250,000,000 | 250,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Five | 500,000,000 | 500,000,000 |
Long-term debt maturities, thereafter | 3,975,000,000 | 3,975,000,000 |
Long-term senior notes and debt: | ||
Long Term Debt Maturities Repayments of Principal Variable in Year Four | 450,000,000 | 450,000,000 |
Total long-term notes payable | 6,925,000,000 | 6,925,000,000 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 1,600,000,000 | 1,700,000,000 |
Loan For Federal Financing Bank | 1,200,000,000 | 0 |
Total other long -term debt | 2,883,000,000 | 1,680,000,000 |
Capitalized lease obligations | 40,000,000 | 45,000,000 |
Unamortized debt (discount), net | -11,000,000 | -12,000,000 |
Total long-term debt (annual interest requirement ) | 9,837,000,000 | 8,638,000,000 |
Less amount due within one year | 1,154,000,000 | 5,000,000 |
Long-term debt excluding amount due within one year | 8,683,000,000 | 8,633,000,000 |
Percent capitalization | 44.80% | 46.70% |
Redeemable Preferred and Preference Stock: | ||
Preference stock | 221,000,000 | 221,000,000 |
Preferred stock | 45,000,000 | 45,000,000 |
Total preferred and preference stock of subsidiaries - percent capitalization | 1.40% | 1.40% |
Common Stockholders' Equity: | ||
Common stock | 398,000,000 | 398,000,000 |
Paid-in capital | 6,196,000,000 | 5,633,000,000 |
Retained earnings | 3,835,000,000 | 3,565,000,000 |
Accumulated other comprehensive loss | -8,000,000 | -5,000,000 |
Total Common Stockholders' Equity | 10,421,000,000 | 9,591,000,000 |
Total common stockholders' equity - percent capitalization | 53.80% | 51.90% |
Total stockholders' equity | 10,421,000,000 | 9,591,000,000 |
Total Capitalization | 19,370,000,000 | 18,490,000,000 |
Percent Capitalization | 100.00% | 100.00% |
Georgia Power [Member] | Noncumulative Preferred Stock, $25 par value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preferred stock | 45,000,000 | 45,000,000 |
Georgia Power [Member] | Noncumulative Preferred Stock, $100 par value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | 221,000,000 | 221,000,000 |
Georgia Power [Member] | Noncumulative Preferred Stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Total preferred and preference stock | 266,000,000 | 266,000,000 |
Georgia Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 818,000,000 | 818,000,000 |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2015 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 98,000,000 | 0 |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2016 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 4,000,000 | 4,000,000 |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2018 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 0 | 20,000,000 |
Georgia Power [Member] | Pollution control revenue bonds due 2022-2052 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 763,000,000 | 838,000,000 |
Gulf Power [Member] | ||
Maturity | ||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 0 | 75,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 110,000,000 | 110,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 85,000,000 | 85,000,000 |
Long-term debt maturities, thereafter | 875,000,000 | 675,000,000 |
Long-term senior notes and debt: | ||
Total long-term notes payable | 1,070,000,000 | 945,000,000 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 309,000,000 | 296,000,000 |
Total other long -term debt | 308,955,000 | 295,955,000 |
Unamortized debt (discount), net | -9,361,000 | -7,792,000 |
Total long-term debt (annual interest requirement ) | 1,369,594,000 | 1,233,163,000 |
Less amount due within one year | 0 | 75,000,000 |
Long-term debt excluding amount due within one year | 1,369,594,000 | 1,158,163,000 |
Percent capitalization | 48.50% | 45.60% |
Redeemable Preferred and Preference Stock: | ||
Total redeemable preferred stock - percent capitalization | 5.20% | 5.80% |
Preference stock | 146,504,000 | 146,504,000 |
Common Stockholders' Equity: | ||
Common stock | 483,060,000 | 433,060,000 |
Paid-in capital | 559,797,000 | 552,681,000 |
Retained earnings | 267,470,000 | 250,494,000 |
Accumulated other comprehensive loss | -737,000 | -1,109,000 |
Total Common Stockholders' Equity | 1,309,590,000 | 1,235,126,000 |
Total common stockholders' equity - percent capitalization | 46.30% | 48.60% |
Total stockholders' equity | 1,309,590,000 | 1,235,126,000 |
Total Capitalization | 2,825,688,000 | 2,539,793,000 |
Percent Capitalization | 100.00% | 100.00% |
Gulf Power [Member] | 6% Preference stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | 53,886,000 | 53,886,000 |
Gulf Power [Member] | 6.45 % Preference stock [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | 44,112,000 | 44,112,000 |
Gulf Power [Member] | Five Point Six Percentage Hundred Dollar Par or Stated Value [Member] | ||
Redeemable Preferred and Preference Stock: | ||
Preference stock | 48,506,000 | 48,506,000 |
Gulf Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 239,625,000 | 226,625,000 |
Gulf Power [Member] | Pollution control revenue bonds due 2022-2039 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 69,330,000 | 69,330,000 |
Mississippi Power [Member] | ||
Maturity | ||
Long-term debt maturities, 2016 | 300,000,000 | 300,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Three | 35,000,000 | 35,000,000 |
Long-term Debt, Maturities, Repayments of Principal in Year Four | 125,000,000 | 125,000,000 |
Long-term debt maturities, thereafter | 680,000,000 | 680,000,000 |
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 10.13% | 9.93% |
Adjustable, 2014 | 0 | 11,250,000 |
Long Term Debt Maturities Repayments of Principal Adjustable in Year Two | 775,000,000 | 525,000,000 |
Total long-term notes payable | 1,915,000,000 | 1,676,250,000 |
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 82,700,000 | 82,700,000 |
Taxable Revenue Bonds | 11,300,000 | |
Total other long -term debt | 352,695,000 | 352,695,000 |
Capitalized lease obligations | 79,679,000 | 82,217,000 |
Unamortized debt premium (related to plant acquisition) | 62,701,000 | 71,807,000 |
Unamortized debt discount | -1,921,000 | -2,113,000 |
Total long-term debt (annual interest requirement ) | 2,408,154,000 | 2,180,856,000 |
Less amount due within one year | 777,667,000 | 13,789,000 |
Long-term debt excluding amount due within one year | 1,630,487,000 | 2,167,067,000 |
Percent capitalization | 43.50% | 49.60% |
Redeemable Preferred and Preference Stock: | ||
Total redeemable preferred stock - percent capitalization | 0.90% | 0.70% |
Preferred stock | 32,780,000 | 32,780,000 |
Common Stockholders' Equity: | ||
Common stock | 37,691,000 | 37,691,000 |
Paid-in capital | 2,612,136,000 | 2,376,595,000 |
Retained earnings | -558,552,000 | -229,871,000 |
Accumulated other comprehensive loss | -7,015,000 | -7,864,000 |
Total Common Stockholders' Equity | 2,084,260,000 | 2,176,551,000 |
Total common stockholders' equity - percent capitalization | 55.60% | 49.70% |
Total stockholders' equity | 2,084,260,000 | 2,176,551,000 |
Total Capitalization | 3,747,527,000 | 4,376,398,000 |
Percent Capitalization | 100.00% | 100.00% |
Mississippi Power [Member] | Pollution control revenue bonds due 2028 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 42,625,000 | 42,625,000 |
Mississippi Power [Member] | Pollution control revenue bonds due 2020-2028 [Member] | ||
Pollution control revenue bonds -- | ||
Long-term pollution control bonds | 40,070,000 | 40,070,000 |
Mississippi Power [Member] | Plant Daniel revenue bonds due 2021 [Member] | ||
Long-term senior notes and debt: | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
Pollution control revenue bonds -- | ||
Taxable Revenue Bonds | $270,000,000 | $270,000,000 |
Consolidated_Statements_of_Cap1
Consolidated Statements of Capitalization (Parenthetical) (USD $) | 12 Months Ended | |
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Common stock, Par value (in dollars per share) | 5 | 5 |
Common stock, shares authorized | 1,500,000,000 | 1,500,000,000 |
Common stock, shares issued | 909,000,000 | 893,000,000 |
Treasury shares | 700,000 | 5,700,000 |
Annual interest requirement | 857 | |
Annual dividend requirement | 48 | |
Redeemable Preferred Stock, $1 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 1 | 1 |
Redeemable Cumulative preferred stock, Authorized | 28,000,000 | 28,000,000 |
Redeemable Cumulative preferred stock, Outstanding | 12,000,000 | 12,000,000 |
Redeemable Preferred Stock, $1 par value [Member] | Cumulative Preferred Stock [Member] | ||
Dividend Rate, Minimum | 5.20% | 5.20% |
Dividend Rate, Maximum | 5.83% | 5.83% |
Redeemable Preferred Stock, $100 par or stated value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 100 | 100 |
Redeemable Cumulative preferred stock, Authorized | 20,000,000 | 20,000,000 |
Redeemable Cumulative preferred stock, Outstanding | 1,000,000 | 1,000,000 |
Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member] | ||
Dividend Rate, Minimum | 4.20% | 4.20% |
Dividend Rate, Maximum | 5.44% | 5.44% |
Redeemable Preferred Stock, $25 stated value | ||
Preferred Stock, Par or Stated Value Per Share | 25 | 25 |
Preference Stock , $100 par or stated value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 100 | 100 |
Preference stock, Outstanding | 4,000,000 | 4,000,000 |
Dividend Rate, Minimum | 5.60% | 5.60% |
Dividend Rate, Maximum | 6.50% | 6.50% |
Preference Stock, $1 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 1 | 1 |
Preference stock, Authorized | 65,000,000 | 65,000,000 |
Preference stock, Outstanding | 14,000,000 | 14,000,000 |
Dividend Rate, Minimum | 5.63% | 5.63% |
Dividend Rate, Maximum | 6.50% | 6.50% |
Redeemable Preferred Stock [Member] | ||
Annual dividend requirement | 20 | |
Noncumulative Preferred Stock [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 25 | 25 |
Preference stock, Authorized | 60,000,000 | 60,000,000 |
Preference stock, Outstanding | 2,000,000 | 2,000,000 |
Dividend Rate, Minimum | 6.00% | 6.00% |
Dividend Rate, Maximum | 6.13% | 6.13% |
2014 | ||
Fixed stated interest rate of debt obligation | 1.29% | |
Interest Rates, Minimum | 3.25% | |
Interest Rates, Maximum | 4.90% | |
2015 [Member] | ||
Interest Rates, Minimum | 0.55% | 0.55% |
Interest Rates, Maximum | 5.25% | 5.25% |
2016 | ||
Interest Rates, Minimum | 1.95% | 1.95% |
Interest Rates, Maximum | 5.30% | 5.30% |
2017 | ||
Interest Rates, Minimum | 1.30% | 1.30% |
Interest Rates, Maximum | 5.90% | 5.90% |
2018 | ||
Interest Rates, Minimum | 2.20% | 2.20% |
Interest Rates, Maximum | 5.40% | 5.40% |
2019 | ||
Fixed stated interest rate of debt obligation | 4.55% | 4.55% |
Interest Rates, Minimum | 2.15% | 2.15% |
Interest Rates, Maximum | 5.55% | 5.55% |
2020 through 2051 | ||
Interest Rates, Minimum | 1.63% | 1.63% |
Interest Rates, Maximum | 6.38% | 6.38% |
Pollution control revenue bonds variable rate, Due 2016 [Member] | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Pollution control revenue bonds variable rate, Due 2018 [Member] | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Pollution control revenue bonds variable rate, Due 2015 [Member] | ||
Interest Rates, Minimum | 0.03% | |
Interest Rates, Maximum | 0.04% | |
Plant Daniel revenue bonds due 2021 [Member] | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
Debt Due Two Thousand Forty Four [Member] | ||
Interest Rates, Minimum | 3.00% | |
Interest Rates, Maximum | 3.86% | |
Affiliate trusts, variable rate, due 2042 [Member] | ||
Fixed stated interest rate of debt obligation | 3.36% | |
Pollution control revenue bonds variable rate, Due 2020 to 2052 [Member] | ||
Interest Rates, Minimum | 0.01% | |
Interest Rates, Maximum | 0.09% | |
Pollution control revenue bonds due 2022 through 2049 [Member] | ||
Interest Rates, Minimum | 0.28% | 0.28% |
Interest Rates, Maximum | 6.00% | 6.00% |
Pollution control revenue bonds variable rate, Due 2017 [Member] | ||
Interest Rates, Minimum | 0.04% | |
Interest Rates, Maximum | 0.06% | |
Adjustable Rate Loans [Member] | 2015 [Member] | ||
Interest Rates, Minimum | 0.77% | 0.77% |
Interest Rates, Maximum | 1.17% | 1.17% |
Adjustable Rate Loans [Member] | 2016 | ||
Interest Rates, Minimum | 0.56% | |
Interest Rates, Maximum | 0.63% | |
Adjustable Rate Loans [Member] | 2017 | ||
Interest Rates, Minimum | 0.56% | |
Interest Rates, Maximum | 0.63% | |
Alabama Power [Member] | ||
Common stock, Par value (in dollars per share) | 40 | 40 |
Common stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, shares outstanding | 30,537,500 | 30,537,500 |
Annual interest requirement | 259 | |
Annual dividend requirement | 21 | |
Alabama Power [Member] | Redeemable Preferred Stock, $1 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 1 | 1 |
Redeemable Cumulative preferred stock, Authorized | 27,500,000 | 27,500,000 |
Redeemable Cumulative preferred stock, Outstanding | 12,000,000 | 12,000,000 |
Dividend Rate, Minimum | 5.20% | 5.20% |
Dividend Rate, Maximum | 5.83% | 5.83% |
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 100 | 100 |
Redeemable Cumulative preferred stock, Authorized | 3,850,000 | 3,850,000 |
Redeemable Cumulative preferred stock, Outstanding | 475,115 | 475,115 |
Alabama Power [Member] | Redeemable Preferred Stock, $100 par or stated value [Member] | Cumulative Preferred Stock [Member] | ||
Dividend Rate, Minimum | 4.20% | 4.20% |
Dividend Rate, Maximum | 4.92% | 4.92% |
Alabama Power [Member] | Redeemable Preferred Stock, $25 stated value | ||
Preferred Stock, Par or Stated Value Per Share | 25 | 25 |
Alabama Power [Member] | Preference Stock, $1 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 1 | 1 |
Dividend Rate, Minimum | 5.63% | 5.63% |
Dividend Rate, Maximum | 6.50% | 6.50% |
Alabama Power [Member] | Redeemable Preferred Stock [Member] | ||
Annual dividend requirement | 18 | |
Alabama Power [Member] | Noncumulative Preferred Stock [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 25 | 25 |
Preference stock, Authorized | 40,000,000 | 40,000,000 |
Preference stock, Outstanding | 14,000,000 | 14,000,000 |
Alabama Power [Member] | 2015 [Member] | ||
Fixed stated interest rate of debt obligation | 0.55% | 0.55% |
Alabama Power [Member] | 2016 | ||
Fixed stated interest rate of debt obligation | 5.20% | 5.20% |
Alabama Power [Member] | 2019 | ||
Fixed stated interest rate of debt obligation | 5.13% | 5.13% |
Alabama Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Thirty Five to Two Thousand Forty Two [Member] | ||
Interest Rates, Minimum | 3.38% | 3.38% |
Interest Rates, Maximum | 6.13% | 6.13% |
Alabama Power [Member] | Maturity of Long Term Senior Notes And Debt Two Thousand Seventeen [Member] | ||
Interest Rates, Minimum | 5.50% | 5.50% |
Interest Rates, Maximum | 5.55% | 5.55% |
Alabama Power [Member] | Pollution control revenue bonds due 2034 [Member] | ||
Interest Rates, Minimum | 0.28% | 0.28% |
Interest Rates, Maximum | 5.00% | 5.00% |
Alabama Power [Member] | Pollution control revenue bonds due 2021-2038 [Member] | ||
Interest Rates, Minimum | 0.01% | |
Interest Rates, Maximum | 0.06% | |
Alabama Power [Member] | Pollution control revenue bonds due 2015 [Member] | ||
Fixed stated interest rate of debt obligation | 0.03% | |
Alabama Power [Member] | Maturity Of Pollution Control Bonds Two Thousand Seventeen [Member] | ||
Interest Rates, Minimum | 0.04% | |
Interest Rates, Maximum | 0.06% | |
Alabama Power [Member] | Affiliate trusts, variable rate, due 2042 [Member] | ||
Fixed stated interest rate of debt obligation | 3.36% | |
Georgia Power [Member] | ||
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares outstanding | 9,261,500 | 9,261,500 |
Annual interest requirement | 342 | |
Annual dividend requirement | 17 | |
Georgia Power [Member] | Noncumulative Preferred Stock, $25 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 25 | 25 |
Preference stock, Authorized | 50,000,000 | 50,000,000 |
Preference stock, Outstanding | 1,800,000 | 1,800,000 |
Dividend Rate | 6.13% | 6.13% |
Georgia Power [Member] | Noncumulative Preferred Stock, $100 par value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 100 | 100 |
Preference stock, Authorized | 15,000,000 | 15,000,000 |
Preference stock, Outstanding | 2,250,000 | 2,250,000 |
Dividend Rate | 6.50% | 6.50% |
Georgia Power [Member] | 2015 [Member] | ||
Interest Rates, Minimum | 0.63% | 0.63% |
Interest Rates, Maximum | 5.25% | 5.25% |
Georgia Power [Member] | 2016 | ||
Fixed stated interest rate of debt obligation | 3.00% | 3.00% |
Georgia Power [Member] | 2017 | ||
Fixed stated interest rate of debt obligation | 5.70% | 5.70% |
Georgia Power [Member] | 2018 | ||
Fixed stated interest rate of debt obligation | 5.40% | 5.40% |
Georgia Power [Member] | 2019 | ||
Fixed stated interest rate of debt obligation | 4.25% | 4.25% |
Georgia Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Twenty Two to Two Thousand Forty Three [Member] | ||
Interest Rates, Minimum | 2.85% | 2.85% |
Interest Rates, Maximum | 5.95% | 5.95% |
Georgia Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Sixteen [Member] | ||
Interest Rates, Minimum | 0.56% | |
Interest Rates, Maximum | 0.63% | |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2016 [Member] | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Georgia Power [Member] | Pollution control revenue bonds variable rate, Due 2018 [Member] | ||
Fixed stated interest rate of debt obligation | 0.04% | |
Georgia Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Interest Rates, Minimum | 0.80% | 0.80% |
Interest Rates, Maximum | 4.00% | 4.00% |
Georgia Power [Member] | Debt Due Two Thousand Forty Four [Member] | ||
Interest Rates, Minimum | 3.00% | |
Interest Rates, Maximum | 3.86% | |
Georgia Power [Member] | Variable rate, Due 2022-2052 [Member] | ||
Interest Rates, Minimum | 0.01% | |
Interest Rates, Maximum | 0.09% | |
Georgia Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Fifteen [Member] | ||
Interest Rates, Minimum | 0.03% | |
Interest Rates, Maximum | 0.04% | |
Gulf Power [Member] | ||
Preference stock, Authorized | 20,000,000 | 20,000,000 |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares outstanding | 5,442,717 | 4,942,717 |
Annual interest requirement | 57.5 | |
Annual dividend requirement | 9 | |
Gulf Power [Member] | Preference Stock , $100 par or stated value [Member] | ||
Preferred Stock, Par or Stated Value Per Share | 100 | 100 |
Preference stock, Outstanding | 550,000 | 550,000 |
Gulf Power [Member] | Preference Stock Type Three [Member] | ||
Preference stock, Outstanding | 450,000 | 450,000 |
Gulf Power [Member] | Preference Stock Type Four [Member] | ||
Preference stock, Outstanding | 500,000 | 500,000 |
Gulf Power [Member] | Preference Stock, $1 par value [Member] | ||
Preference stock, Authorized | 10,000,000 | 10,000,000 |
Gulf Power [Member] | 2014 | ||
Fixed stated interest rate of debt obligation | 4.90% | |
Gulf Power [Member] | 2017 | ||
Fixed stated interest rate of debt obligation | 5.30% | 5.30% |
Gulf Power [Member] | 2018 | ||
Fixed stated interest rate of debt obligation | 5.90% | 5.90% |
Gulf Power [Member] | 2020-2051 | ||
Interest Rates, Minimum | 3.10% | 3.10% |
Interest Rates, Maximum | 5.75% | 5.75% |
Gulf Power [Member] | Pollution control revenue bonds due 2022 - 2049 [Member] | ||
Interest Rates, Minimum | 0.55% | 0.55% |
Interest Rates, Maximum | 6.00% | 6.00% |
Gulf Power [Member] | Pollution control revenue bonds due 2022-2039 [Member] | ||
Interest Rates, Minimum | 0.02% | |
Interest Rates, Maximum | 0.04% | |
Gulf Power [Member] | 6.0% preference stock | Preference Stock , $100 par or stated value [Member] | ||
Fixed stated interest rate of debt obligation | 6.00% | 6.00% |
Gulf Power [Member] | 6.45% preference stock | Preference Stock , $100 par or stated value [Member] | ||
Fixed stated interest rate of debt obligation | 6.45% | 6.45% |
Gulf Power [Member] | Five Point Six Percent Preference Stock [Member] | Preference Stock , $100 par or stated value [Member] | ||
Fixed stated interest rate of debt obligation | 5.60% | 5.60% |
Mississippi Power [Member] | ||
Fixed stated interest rate of debt obligation | 10.13% | 9.93% |
Preferred Stock, Par or Stated Value Per Share | 100 | 100 |
Redeemable Cumulative preferred stock, Authorized | 1,244,139 | 1,244,139 |
Redeemable Cumulative preferred stock, Outstanding | 334,210 | 334,210 |
Common stock, shares authorized | 1,130,000 | 1,130,000 |
Common stock, shares outstanding | 1,121,000 | 1,121,000 |
Annual interest requirement | 78 | |
Annual dividend requirement | 1.7 | |
Dividend Rate, Minimum | 4.40% | 4.40% |
Dividend Rate, Maximum | 5.25% | 5.25% |
Mississippi Power [Member] | 2016 | ||
Fixed stated interest rate of debt obligation | 2.35% | 2.35% |
Mississippi Power [Member] | 2017 | ||
Fixed stated interest rate of debt obligation | 5.60% | 5.60% |
Mississippi Power [Member] | Maturity of Long Term Senior Notes and Debt Two Thousand Thirty Five Thousand Forty Two [Member] | ||
Interest Rates, Minimum | 1.63% | 1.63% |
Interest Rates, Maximum | 5.40% | 5.40% |
Mississippi Power [Member] | 2019 | ||
Fixed stated interest rate of debt obligation | 5.55% | 5.55% |
Mississippi Power [Member] | 2028 | ||
Fixed stated interest rate of debt obligation | 5.15% | 5.15% |
Mississippi Power [Member] | Pollution control revenue bonds due 2020-2028 [Member] | ||
Interest Rates, Minimum | 0.02% | |
Interest Rates, Maximum | 0.06% | |
Mississippi Power [Member] | Plant Daniel revenue bonds due 2021 [Member] | ||
Fixed stated interest rate of debt obligation | 7.13% | 7.13% |
Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Fourteen [Member] | ||
Fixed stated interest rate of debt obligation | 1.29% | |
Mississippi Power [Member] | Maturity of Long Term Notes Payable Variable Rate Due Two Thousand Fifteen [Member] | ||
Interest Rates, Minimum | 0.77% | |
Interest Rates, Maximum | 1.17% |
Consolidated_Statements_of_Com2
Consolidated Statements of Common Stockholders Equity (USD $) | Total | Common Stock [Member] | Treasury Stock [Member] | Paid In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Preferred And Preference Stock [Member] | Noncontrolling Interest [Member] | Alabama Power [Member] | Alabama Power [Member] | Alabama Power [Member] | Alabama Power [Member] | Alabama Power [Member] | Georgia Power [Member] | Georgia Power [Member] | Georgia Power [Member] | Georgia Power [Member] | Georgia Power [Member] | Gulf Power [Member] | Gulf Power [Member] | Gulf Power [Member] | Gulf Power [Member] | Gulf Power [Member] | Mississippi Power [Member] | Mississippi Power [Member] | Mississippi Power [Member] | Mississippi Power [Member] | Mississippi Power [Member] | Southern Power [Member] | Southern Power [Member] | Southern Power [Member] | Southern Power [Member] | Southern Power [Member] | Southern Power [Member] | Southern Power [Member] | |
Share data in Thousands, except Per Share data, unless otherwise specified | Common Stock [Member] | Paid In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Common Stock [Member] | Paid In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Common Stock [Member] | Paid In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Common Stock [Member] | Paid In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Common Stock [Member] | Paid In Capital [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Common Stockholder's Equity Not Including Noncontrolling Interest [Member] | Noncontrolling Interest [Member] | ||||||||||||||
Beginning Balance at Dec. 31, 2011 | $18,285,000,000 | $4,328,000,000 | ($17,000,000) | $4,410,000,000 | $8,968,000,000 | ($111,000,000) | $707,000,000 | $0 | $5,342,000,000 | $1,222,000,000 | $2,182,000,000 | $1,956,000,000 | ($18,000,000) | $9,023,000,000 | $398,000,000 | $5,522,000,000 | $3,112,000,000 | ($9,000,000) | $1,124,948,000 | $353,060,000 | $542,709,000 | $231,333,000 | ($2,154,000) | $1,049,217,000 | $37,691,000 | $694,855,000 | $325,568,000 | ($8,897,000) | $1,468,682,000 | $0 | $1,028,210,000 | $447,301,000 | ($6,829,000) | $1,468,682,000 | ||
Beginning Balance, Shares at Dec. 31, 2011 | 865,664 | 539 | 31,000 | 9,000 | 4,143 | 1,121 | 1 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 175,285,000 | 175,285,000 | 175,285,000 | |||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 2,350,000,000 | [1] | 2,350,000,000 | 704,000,000 | 704,000,000 | 1,168,000,000 | 1,168,000,000 | 125,932,000 | 125,932,000 | 99,942,000 | 99,942,000 | |||||||||||||||||||||||||
Capital contributions from parent company | 45,000,000 | 45,000,000 | 63,000,000 | 63,000,000 | 5,089,000 | 5,089,000 | 706,665,000 | 706,665,000 | -662,000 | -662,000 | -662,000 | |||||||||||||||||||||||||
Other comprehensive income (loss) | -12,000,000 | -12,000,000 | -9,000,000 | -9,000,000 | 2,000,000 | 2,000,000 | 573,000 | 573,000 | 184,000 | 184,000 | 6,053,000 | 6,053,000 | 6,053,000 | |||||||||||||||||||||||
Stock issued, shares | 12,139 | 400 | ||||||||||||||||||||||||||||||||||
Stock issued | 397,000,000 | 61,000,000 | 336,000,000 | 40,000,000 | 40,000,000 | |||||||||||||||||||||||||||||||
Stock repurchased, at cost, shares | -9,440 | |||||||||||||||||||||||||||||||||||
Stock repurchased, at cost | -430,000,000 | -430,000,000 | ||||||||||||||||||||||||||||||||||
Stock-based compensation | 106,000,000 | 106,000,000 | ||||||||||||||||||||||||||||||||||
Cash dividends on common stock | -1,693,000,000 | -1,693,000,000 | -684,000,000 | -684,000,000 | -983,000,000 | -983,000,000 | -115,800,000 | -115,800,000 | -106,800,000 | -106,800,000 | -127,000,000 | -127,000,000 | -127,000,000 | |||||||||||||||||||||||
Common Stock, Dividends, Per Share, Cash Paid (in dollars per share) | $1.94 | |||||||||||||||||||||||||||||||||||
Capital contributions from noncontrolling interests | 0 | |||||||||||||||||||||||||||||||||||
Other, shares | -56 | |||||||||||||||||||||||||||||||||||
Other | 1,000,000 | -3,000,000 | 3,000,000 | 1,000,000 | -1,000 | -1,000 | ||||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2012 | 19,004,000,000 | 4,389,000,000 | -450,000,000 | 4,855,000,000 | 9,626,000,000 | -123,000,000 | 0 | 5,398,000,000 | 1,222,000,000 | 2,227,000,000 | 1,976,000,000 | -27,000,000 | 9,273,000,000 | 398,000,000 | 5,585,000,000 | 3,297,000,000 | -7,000,000 | 1,180,742,000 | 393,060,000 | 547,798,000 | 241,465,000 | -1,581,000 | 1,749,208,000 | 37,691,000 | 1,401,520,000 | 318,710,000 | -8,713,000 | 1,522,357,000 | 0 | 1,027,548,000 | 495,585,000 | -776,000 | 1,522,357,000 | |||
Ending Balance, Shares at Dec. 31, 2012 | 877,803 | 10,035 | 31,000 | 9,000 | 4,543 | 1,121 | 1 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 81,000,000 | 141,000,000 | 197,000,000 | 21,792,000 | -246,321,000 | 29,192,000 | ||||||||||||||||||||||||||||||
Common Stock, Dividends, Per Share, Cash Paid (in dollars per share) | $0.49 | |||||||||||||||||||||||||||||||||||
Ending Balance at Mar. 31, 2013 | ||||||||||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2012 | 19,004,000,000 | 4,389,000,000 | -450,000,000 | 4,855,000,000 | 9,626,000,000 | -123,000,000 | 707,000,000 | 0 | 5,398,000,000 | 1,222,000,000 | 2,227,000,000 | 1,976,000,000 | -27,000,000 | 9,273,000,000 | 398,000,000 | 5,585,000,000 | 3,297,000,000 | -7,000,000 | 1,180,742,000 | 393,060,000 | 547,798,000 | 241,465,000 | -1,581,000 | 1,749,208,000 | 37,691,000 | 1,401,520,000 | 318,710,000 | -8,713,000 | 1,522,357,000 | 0 | 1,027,548,000 | 495,585,000 | -776,000 | 1,522,357,000 | ||
Beginning Balance, Shares at Dec. 31, 2012 | 877,803 | 10,035 | 31,000 | 9,000 | 4,543 | 1,121 | 1 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 165,533,000 | 165,533,000 | 165,533,000 | |||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 1,644,000,000 | [1],[2] | 1,644,000,000 | 712,000,000 | 712,000,000 | 1,174,000,000 | 1,174,000,000 | 124,429,000 | 124,429,000 | -476,625,000 | -476,625,000 | |||||||||||||||||||||||||
Capital contributions from parent company | 35,000,000 | 35,000,000 | 48,000,000 | 48,000,000 | 4,883,000 | 4,883,000 | 975,075,000 | 975,075,000 | 1,487,000 | 1,487,000 | 1,487,000 | |||||||||||||||||||||||||
Other comprehensive income (loss) | 48,000,000 | 48,000,000 | 1,000,000 | 1,000,000 | 2,000,000 | 2,000,000 | 472,000 | 472,000 | 849,000 | 849,000 | 3,695,000 | 3,695,000 | 3,695,000 | |||||||||||||||||||||||
Stock issued, shares | 14,930 | 4,443 | 400 | |||||||||||||||||||||||||||||||||
Stock issued | 765,000,000 | 72,000,000 | 203,000,000 | 441,000,000 | 49,000,000 | 40,000,000 | 40,000,000 | 0 | ||||||||||||||||||||||||||||
Stock-based compensation | 65,000,000 | 65,000,000 | ||||||||||||||||||||||||||||||||||
Cash dividends on common stock | -1,762,000,000 | -1,762,000,000 | -644,000,000 | -644,000,000 | -907,000,000 | -907,000,000 | -115,400,000 | -115,400,000 | -71,956,000 | -71,956,000 | -129,120,000 | -129,120,000 | -129,120,000 | |||||||||||||||||||||||
Common Stock, Dividends, Per Share, Cash Paid (in dollars per share) | $2.01 | |||||||||||||||||||||||||||||||||||
Capital contributions from noncontrolling interests | 0 | |||||||||||||||||||||||||||||||||||
Other, shares | -55 | |||||||||||||||||||||||||||||||||||
Other | 0 | -3,000,000 | 1,000,000 | 2,000,000 | 1,000,000 | 1,000,000 | ||||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 19,764,000,000 | 4,461,000,000 | -250,000,000 | 5,362,000,000 | 9,510,000,000 | -75,000,000 | 756,000,000 | 5,502,000,000 | 1,222,000,000 | 2,262,000,000 | 2,044,000,000 | -26,000,000 | 9,591,000,000 | 398,000,000 | 5,633,000,000 | 3,565,000,000 | -5,000,000 | 1,235,126,000 | 433,060,000 | 552,681,000 | 250,494,000 | -1,109,000 | 2,176,551,000 | 37,691,000 | 2,376,595,000 | -229,871,000 | -7,864,000 | 1,563,952,000 | 0 | 1,029,035,000 | 531,998,000 | 2,919,000 | 1,563,952,000 | |||
Ending Balance, Shares at Dec. 31, 2013 | 892,733 | 5,647 | 31,000 | 9,000 | 4,943 | 1,121 | 1 | |||||||||||||||||||||||||||||
Beginning Balance at Sep. 30, 2013 | ||||||||||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 414,000,000 | 140,000,000 | 208,000,000 | 25,301,000 | 12,921,000 | 23,266,000 | ||||||||||||||||||||||||||||||
Common Stock, Dividends, Per Share, Cash Paid (in dollars per share) | $0.51 | |||||||||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 19,764,000,000 | 5,502,000,000 | 1,222,000,000 | 9,591,000,000 | 398,000,000 | 1,235,126,000 | 2,176,551,000 | 37,691,000 | 1,563,952,000 | 0 | ||||||||||||||||||||||||||
Ending Balance, Shares at Dec. 31, 2013 | 31,000 | 9,000 | 1,121 | 1 | ||||||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 351,000,000 | 187,000,000 | 266,000,000 | 36,743,000 | -172,048,000 | 33,471,000 | ||||||||||||||||||||||||||||||
Common Stock, Dividends, Per Share, Cash Paid (in dollars per share) | $0.51 | |||||||||||||||||||||||||||||||||||
Ending Balance at Mar. 31, 2014 | ||||||||||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2013 | 19,764,000,000 | 4,461,000,000 | -250,000,000 | 5,362,000,000 | 9,510,000,000 | -75,000,000 | 756,000,000 | 0 | 5,502,000,000 | 1,222,000,000 | 2,262,000,000 | 2,044,000,000 | -26,000,000 | 9,591,000,000 | 398,000,000 | 5,633,000,000 | 3,565,000,000 | -5,000,000 | 1,235,126,000 | 433,060,000 | 552,681,000 | 250,494,000 | -1,109,000 | 2,176,551,000 | 37,691,000 | 2,376,595,000 | -229,871,000 | -7,864,000 | 1,563,952,000 | 0 | 1,029,035,000 | 531,998,000 | 2,919,000 | 1,563,952,000 | ||
Beginning Balance, Shares at Dec. 31, 2013 | 892,733 | 5,647 | 31,000 | 9,000 | 4,943 | 1,121 | 1 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||
Net income attributable to Southern Power Company | 172,300,000 | 172,300,000 | 172,300,000 | |||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 1,963,000,000 | [1],[2] | 1,963,000,000 | 761,000,000 | 761,000,000 | 1,225,000,000 | 1,225,000,000 | 140,176,000 | 140,176,000 | -328,681,000 | -328,681,000 | |||||||||||||||||||||||||
Capital contributions from parent company | 42,000,000 | 42,000,000 | 563,000,000 | 563,000,000 | 7,116,000 | 7,116,000 | 235,541,000 | 235,541,000 | 146,357,000 | 146,357,000 | 146,357,000 | |||||||||||||||||||||||||
Other comprehensive income (loss) | -53,000,000 | -53,000,000 | -3,000,000 | -3,000,000 | -3,000,000 | -3,000,000 | 372,000 | 372,000 | 849,000 | 849,000 | 367,000 | 367,000 | 367,000 | |||||||||||||||||||||||
Stock issued, shares | 15,769 | 4,996 | 500 | |||||||||||||||||||||||||||||||||
Stock issued | 806,000,000 | 78,000,000 | 227,000,000 | 501,000,000 | 0 | 50,000,000 | 50,000,000 | |||||||||||||||||||||||||||||
Stock-based compensation | 86,000,000 | 86,000,000 | ||||||||||||||||||||||||||||||||||
Cash dividends on common stock | -1,866,000,000 | -1,866,000,000 | -550,000,000 | -550,000,000 | -954,000,000 | -954,000,000 | -123,200,000 | -123,200,000 | -131,120,000 | -131,120,000 | -131,120,000 | |||||||||||||||||||||||||
Common Stock, Dividends, Per Share, Cash Paid (in dollars per share) | $2.08 | |||||||||||||||||||||||||||||||||||
Capital contributions from noncontrolling interests | 221,000,000 | 221,000,000 | 220,734,000 | 220,734,000 | ||||||||||||||||||||||||||||||||
Noncontrolling Interest in Net Income (Loss) Other Noncontrolling Interests, Redeemable | 2,000,000 | 2,000,000 | -1,246,000 | -1,246,000 | ||||||||||||||||||||||||||||||||
Other, shares | -74 | |||||||||||||||||||||||||||||||||||
Other | 7,000,000 | -3,000,000 | 6,000,000 | 2,000,000 | 2,000,000 | -1,000,000 | -1,000,000 | |||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2014 | 20,926,000,000 | 4,539,000,000 | -26,000,000 | 5,955,000,000 | 9,609,000,000 | -128,000,000 | 756,000,000 | 221,000,000 | 5,752,000,000 | 1,222,000,000 | 2,304,000,000 | 2,255,000,000 | -29,000,000 | 10,421,000,000 | 398,000,000 | 6,196,000,000 | 3,835,000,000 | -8,000,000 | 1,309,590,000 | 483,060,000 | 559,797,000 | 267,470,000 | -737,000 | 2,084,260,000 | 37,691,000 | 2,612,136,000 | -558,552,000 | -7,015,000 | 1,971,344,000 | 0 | 1,175,392,000 | 573,178,000 | 3,286,000 | 1,751,856,000 | 219,488,000 | |
Ending Balance, Shares at Dec. 31, 2014 | 908,502 | 725 | 31,000 | 9,000 | 5,443 | 1,121 | 1 | |||||||||||||||||||||||||||||
Beginning Balance at Sep. 30, 2014 | ||||||||||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||||||||||||||||||||||||||||||
Net income after dividends on preferred and preference stock | 283,000,000 | 119,000,000 | 123,000,000 | 22,789,000 | -24,058,000 | 44,386,000 | ||||||||||||||||||||||||||||||
Common Stock, Dividends, Per Share, Cash Paid (in dollars per share) | $0.53 | |||||||||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2014 | $20,926,000,000 | $5,752,000,000 | $1,222,000,000 | $10,421,000,000 | $398,000,000 | $1,309,590,000 | $2,084,260,000 | $37,691,000 | $1,971,344,000 | $0 | ||||||||||||||||||||||||||
Ending Balance, Shares at Dec. 31, 2014 | 31,000 | 9,000 | 1,121 | 1 | ||||||||||||||||||||||||||||||||
[1] | After dividends on preferred and preference stock of subsidiaries. | |||||||||||||||||||||||||||||||||||
[2] | Segment net income (loss) for the traditional operating companies in 2014 and 2013 includes $868 million in pre-tax charges ($536 million after tax) and $1.2 billion in pre-tax charges ($729 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle b Kemper IGCC Schedule and Cost Estimate" for additional information. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||||||||||||||||
General | ||||||||||||||||||||||||
The Southern Company (Southern Company or the Company) is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment, but is not the primary beneficiary. All material intercompany transactions have been eliminated in consolidation. | ||||||||||||||||||||||||
The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the FERC, and the traditional operating companies are also subject to regulation by their respective state PSCs. The companies follow GAAP in the U.S. and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | ||||||||||||||||||||||||
The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Retiree benefit plans | $ | 3,469 | $ | 1,760 | (a,p) | |||||||||||||||||||
Deferred income tax charges | 1,458 | 1,376 | (b) | |||||||||||||||||||||
Loss on reacquired debt | 267 | 293 | (c) | |||||||||||||||||||||
Fuel-hedging-asset | 202 | 58 | (d,p) | |||||||||||||||||||||
Deferred PPA charges | 185 | 180 | (e,p) | |||||||||||||||||||||
Vacation pay | 177 | 171 | (f,p) | |||||||||||||||||||||
Under recovered regulatory clause revenues | 157 | 70 | (g) | |||||||||||||||||||||
Kemper IGCC regulatory assets | 148 | 76 | (h) | |||||||||||||||||||||
Asset retirement obligations-asset | 119 | 145 | (b,p) | |||||||||||||||||||||
Nuclear outage | 99 | 78 | (g) | |||||||||||||||||||||
Property damage reserves-asset | 98 | 37 | (i) | |||||||||||||||||||||
Cancelled construction projects | 67 | 70 | (j) | |||||||||||||||||||||
Environmental remediation-asset | 64 | 62 | (k,p) | |||||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 57 | 65 | (l) | |||||||||||||||||||||
Other regulatory assets | 195 | 222 | (m) | |||||||||||||||||||||
Other cost of removal obligations | (1,229 | ) | (1,289 | ) | (b) | |||||||||||||||||||
Kemper regulatory liability (Mirror CWIP) | (271 | ) | (91 | ) | (h) | |||||||||||||||||||
Deferred income tax credits | (192 | ) | (203 | ) | (b) | |||||||||||||||||||
Property damage reserves-liability | (181 | ) | (191 | ) | (n) | |||||||||||||||||||
Asset retirement obligations-liability | (130 | ) | (139 | ) | (b,p) | |||||||||||||||||||
Other regulatory liabilities | (95 | ) | (126 | ) | (o) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 4,664 | $ | 2,624 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the two-year period from January 2015 through December 2016 in accordance with Georgia Power's 2013 ARP. See Note 3 under "Retail Regulatory Matters – Georgia Power – Rate Plans" for additional information. At December 31, 2014, other cost of removal obligations included $8.4 million recorded as authorized by the Florida PSC in the Settlement Agreement approved in December 2013 (Gulf Power Settlement Agreement). | |||||||||||||||||||||||
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. | |||||||||||||||||||||||
(d) | Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||||||||||||||||||
(e) | Recovered over the life of the PPA for periods up to nine years. | |||||||||||||||||||||||
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(g) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years. | |||||||||||||||||||||||
(h) | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||||||||||||||
(i) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding eight years. | |||||||||||||||||||||||
(j) | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||||||||||||||||||
(k) | Recovered through the environmental cost recovery clause when the remediation is performed. | |||||||||||||||||||||||
(l) | Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years. | |||||||||||||||||||||||
(m) | Comprised of numerous immaterial components including property taxes, generation site selection/evaluation costs, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding 10 years or, as applicable, over the remaining life of the asset but not beyond 2031. | |||||||||||||||||||||||
(n) | Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. | |||||||||||||||||||||||
(o) | Comprised of numerous immaterial components including over-recovered regulatory clause revenues, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, nuclear disposal fees, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years. | |||||||||||||||||||||||
(p) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
In the event that a portion of a traditional operating company's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power," and "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. | ||||||||||||||||||||||||
Southern Company's electric utility subsidiaries have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | ||||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. | ||||||||||||||||||||||||
Income and Other Taxes | ||||||||||||||||||||||||
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
In accordance with regulatory requirements, deferred federal ITCs for the traditional operating companies are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2014, $16 million in 2013, and $23 million in 2012. At December 31, 2014, all ITCs available to reduce federal income taxes payable had not been utilized. The remaining ITCs will be carried forward and utilized in future years. Additionally, several subsidiaries have state ITCs, which are recognized in the period in which the credit is claimed on the state income tax return. A portion of the state ITCs available to reduce state income taxes payable was not utilized currently and will be carried forward and utilized in future years. | ||||||||||||||||||||||||
Under the American Recovery and Reinvestment Act of 2009 and the American Taxpayer Relief Act of 2012 (ATRA), certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $11.4 million in 2014, $5.5 million in 2013, and $2.6 million in 2012. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $74 million, $158 million, and $45 million for the years ended December 31, 2014, 2013, and 2012, respectively, which had a material impact on cash flows. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $48 million in 2014, $31 million in 2013, and $8 million in 2012. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | ||||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. | ||||||||||||||||||||||||
The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 37,892 | $ | 35,360 | ||||||||||||||||||||
Transmission | 9,884 | 9,289 | ||||||||||||||||||||||
Distribution | 17,123 | 16,499 | ||||||||||||||||||||||
General | 4,198 | 3,958 | ||||||||||||||||||||||
Plant acquisition adjustment | 123 | 123 | ||||||||||||||||||||||
Utility plant in service | 69,220 | 65,229 | ||||||||||||||||||||||
Information technology equipment and software | 244 | 242 | ||||||||||||||||||||||
Communications equipment | 439 | 437 | ||||||||||||||||||||||
Other | 110 | 113 | ||||||||||||||||||||||
Other plant in service | 793 | 792 | ||||||||||||||||||||||
Total plant in service | $ | 70,013 | $ | 66,021 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle. The refueling cycles for Alabama Power's Plant Farley and Georgia Power's Plants Hatch and Vogtle Units 1 and 2 range from 18 to 24 months, depending on the unit. | ||||||||||||||||||||||||
Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below: | ||||||||||||||||||||||||
Asset Balances at | ||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Office building | $ | 61 | $ | 61 | ||||||||||||||||||||
Nitrogen plant | 83 | 83 | ||||||||||||||||||||||
Computer-related equipment | 60 | 62 | ||||||||||||||||||||||
Gas pipeline | 6 | 6 | ||||||||||||||||||||||
Less: Accumulated amortization | (49 | ) | (48 | ) | ||||||||||||||||||||
Balance, net of amortization | $ | 161 | $ | 164 | ||||||||||||||||||||
The amount of non-cash property additions recognized for the years ended December 31, 2014, 2013, and 2012 was $528 million, $411 million, and $524 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2014, 2013, and 2012 was $25 million, $107 million, and $14 million, respectively. | ||||||||||||||||||||||||
Acquisitions | ||||||||||||||||||||||||
Southern Power acquires generation assets as part of its overall growth strategy. Southern Power accounts for business acquisitions from non-affiliates as business combinations. Accordingly, Southern Power has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition was allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition was allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by Southern Power for successful or potential acquisitions have been expensed as incurred. | ||||||||||||||||||||||||
Acquisitions entered into or made by Southern Power during 2014 and 2013 are detailed in the table below: | ||||||||||||||||||||||||
MW Capacity | Percentage | Year | Party Under PPA Contract | PPA Contract Period | Purchase Price | |||||||||||||||||||
Ownership | of | for Plant Output | ||||||||||||||||||||||
Operation | ||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
SG2 Imperial Valley, LLC (a) | 150 | 51% | 2014 | San Diego Gas & | 25 years | $504.70 | (c) | |||||||||||||||||
Electric Company | ||||||||||||||||||||||||
Macho Springs Solar LLC (b) | 50 | 90 | 2014 | El Paso Electric Company | 20 years | $130.00 | (d) | |||||||||||||||||
Adobe Solar, LLC (b) | 20 | 90 | 2014 | Southern California | 20 years | $96.20 | (d) | |||||||||||||||||
Edison Company | ||||||||||||||||||||||||
Campo Verde Solar, LLC (b)(e) | 139 | 90 | 2013 | San Diego Gas & | 20 years | $136.60 | (d) | |||||||||||||||||
Electric Company | ||||||||||||||||||||||||
(a) | This acquisition was made by Southern Power through its subsidiaries Southern Renewable Partnerships, LLC and SG2 Holdings, LLC. SG2 Holdings, LLC is jointly-owned by Southern Power and First Solar, Inc. | |||||||||||||||||||||||
(b) | This acquisition was made by Southern Power and Turner Renewable Energy, LLC through Southern Turner Renewable Energy, LLC. | |||||||||||||||||||||||
(c) | Reflects Southern Power's portion of the purchase price. | |||||||||||||||||||||||
(d) | Reflects 100% of the purchase price, including Turner Renewable Energy, LLC's 10% equity contribution. | |||||||||||||||||||||||
(e) | Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar, Inc. to complete the construction of the solar facility. | |||||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.1% in 2014, 3.3% in 2013, and 3.2% in 2012. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and the FERC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $23.5 billion and $22.5 billion at December 31, 2014 and 2013, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets are now depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. Cost, net of salvage value, of these assets is depreciated on an hours or starts units-of-production basis. The book value of plant-in-service as of December 31, 2014 that is depreciated on a units-of-production basis was approximately $470.2 million. | ||||||||||||||||||||||||
In 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of Georgia Power's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), Georgia Power amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $14 million is being amortized annually by Georgia Power over the three years ending December 31, 2016. See Note 3 under "Retail Regulatory Matters – Georgia Power – Rate Plans" for additional information. | ||||||||||||||||||||||||
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 25 years. Accumulated depreciation for other plant in service totaled $533 million and $513 million at December 31, 2014 and 2013, respectively. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | ||||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Each traditional operating company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The liability for AROs primarily relates to the decommissioning of the Southern Company system's nuclear facilities, Plants Farley, Hatch, and Vogtle. In addition, the Southern Company system has retirement obligations related to various landfill sites, ash ponds, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 2,018 | $ | 1,757 | ||||||||||||||||||||
Liabilities incurred | 18 | 6 | ||||||||||||||||||||||
Liabilities settled | (17 | ) | (16 | ) | ||||||||||||||||||||
Accretion | 102 | 97 | ||||||||||||||||||||||
Cash flow revisions | 80 | 174 | ||||||||||||||||||||||
Balance at end of year | $ | 2,201 | $ | 2,018 | ||||||||||||||||||||
The cash flow revisions in 2014 are primarily related to Alabama Power's and SEGCO's AROs associated with asbestos at their steam generation facilities. The cash flow revisions in 2013 are primarily related to revisions to the nuclear decommissioning ARO based on Alabama Power's updated decommissioning study and Georgia Power's updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, Southern Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $860 million and ongoing post-closure care of approximately $140 million. Certain of the traditional operating companies have previously recorded AROs associated with ash ponds of $506 million, or $468 million on a nominal dollar basis, based on existing state requirements. During 2015, the traditional operating companies will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. Southern Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Nuclear Decommissioning | ||||||||||||||||||||||||
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. | ||||||||||||||||||||||||
Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. | ||||||||||||||||||||||||
The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2014 and 2013, approximately $51 million and $32 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $52 million and $33 million at December 31, 2014 and 2013, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows. | ||||||||||||||||||||||||
At December 31, 2014, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $886 million, debt securities of $638 million, and $19 million of other securities. At December 31, 2013, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $896 million, debt securities of $528 million, and $40 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the lending pool. | ||||||||||||||||||||||||
Sales of the securities held in the Funds resulted in cash proceeds of $913 million, $1.0 billion, and $1.0 billion in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $98 million, of which $2 million related to realized gains and $19 million related to unrealized gains and losses related to securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $181 million, of which $5 million related to realized gains and $119 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $137 million, of which $4 million related to realized gains and $75 million related to unrealized gains related to securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. | ||||||||||||||||||||||||
For Alabama Power, amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the accumulated provisions for decommissioning were as follows: | ||||||||||||||||||||||||
External Trust Funds | Internal Reserves | Total | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Plant Farley | $ | 754 | $ | 713 | $ | 21 | $ | 21 | $ | 775 | $ | 734 | ||||||||||||
Plant Hatch | 496 | 469 | — | — | 496 | 469 | ||||||||||||||||||
Plant Vogtle Units 1 and 2 | 293 | 277 | — | — | 293 | 277 | ||||||||||||||||||
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 2014 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2012 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2: | ||||||||||||||||||||||||
Plant Farley | Plant Hatch | Plant Vogtle | ||||||||||||||||||||||
Units 1 and 2 | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2037 | 2034 | 2047 | |||||||||||||||||||||
Completion year | 2076 | 2068 | 2072 | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 1,362 | $ | 549 | $ | 453 | ||||||||||||||||||
Spent fuel management | — | 131 | 115 | |||||||||||||||||||||
Non-radiated structures | 80 | 51 | 76 | |||||||||||||||||||||
Total site study costs | $ | 1,442 | $ | 731 | $ | 644 | ||||||||||||||||||
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power's annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively. | ||||||||||||||||||||||||
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | ||||||||||||||||||||||||
In accordance with regulatory treatment, the traditional operating companies record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 16.0%, 15.0%, and 8.2% of net income for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
Cash payments for interest totaled $732 million, $759 million, and $803 million in 2014, 2013, and 2012, respectively, net of amounts capitalized of $111 million, $92 million, and $83 million, respectively. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | ||||||||||||||||||||||||
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Storm Damage Reserves | ||||||||||||||||||||||||
Each traditional operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $40 million in 2014 and $28 million in 2013. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2014 and 2013, there were no such additional accruals. See Note 3 under "Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve" and "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively. | ||||||||||||||||||||||||
Leveraged Leases | ||||||||||||||||||||||||
Southern Company has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. | ||||||||||||||||||||||||
Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Net rentals receivable | $ | 1,495 | $ | 1,440 | ||||||||||||||||||||
Unearned income | (752 | ) | (775 | ) | ||||||||||||||||||||
Investment in leveraged leases | 743 | 665 | ||||||||||||||||||||||
Deferred taxes from leveraged leases | (299 | ) | (287 | ) | ||||||||||||||||||||
Net investment in leveraged leases | $ | 444 | $ | 378 | ||||||||||||||||||||
A summary of the components of income from the leveraged leases follows: | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Pretax leveraged lease income (loss) | $ | 24 | $ | (5 | ) | $ | 21 | |||||||||||||||||
Income tax expense | (9 | ) | 2 | (8 | ) | |||||||||||||||||||
Net leveraged lease income (loss) | $ | 15 | $ | (3 | ) | $ | 13 | |||||||||||||||||
Cash and Cash Equivalents | ||||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | ||||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | ||||||||||||||||||||||||
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | ||||||||||||||||||||||||
Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2014, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial. | ||||||||||||||||||||||||
Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | ||||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries. | ||||||||||||||||||||||||
Accumulated OCI (loss) balances, net of tax effects, were as follows: | ||||||||||||||||||||||||
Qualifying | Marketable | Pension and Other | Accumulated Other | |||||||||||||||||||||
Hedges | Securities | Postretirement | Comprehensive | |||||||||||||||||||||
Benefit Plans | Income (Loss) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at December 31, 2013 | $ | (36 | ) | $ | — | $ | (39 | ) | $ | (75 | ) | |||||||||||||
Current period change | (5 | ) | — | (48 | ) | (53 | ) | |||||||||||||||||
Balance at December 31, 2014 | $ | (41 | ) | $ | — | $ | (87 | ) | $ | (128 | ) | |||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||||||||||||||||
General | ||||||||||||||||||||||||
Alabama Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Farley. | ||||||||||||||||||||||||
The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Alabama PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | ||||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $400 million, $340 million, and $340 million during 2014, 2013, and 2012, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $234 million, $211 million, and $218 million during 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $13 million in 2014, $13 million in 2013, and $12 million in 2012. Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $34 million in 2014, $27 million in 2013, and $28 million in 2012. See Note 4 for additional information. | ||||||||||||||||||||||||
The Company has an agreement with Gulf Power under which the Company has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA. In 2009, Gulf Power entered into a PPA for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. The total cost committed by the Company related to the upgrades is approximately $85 million, of which approximately $29 million was spent in 2014. The transmission improvements were completed in 2014. The Company expects to recover a majority of these costs through a tariff with Gulf Power until 2023. The remainder of these costs will be recovered through normal rate mechanisms. | ||||||||||||||||||||||||
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014, 2013, or 2012. | ||||||||||||||||||||||||
Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. | ||||||||||||||||||||||||
The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | ||||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Deferred income tax charges | $ | 525 | $ | 519 | (a,k) | |||||||||||||||||||
Loss on reacquired debt | 80 | 86 | (b) | |||||||||||||||||||||
Vacation pay | 65 | 63 | (c,j) | |||||||||||||||||||||
Under/(over) recovered regulatory clause revenues | 57 | (18 | ) | (d) | ||||||||||||||||||||
Fuel-hedging losses | 53 | 8 | (e) | |||||||||||||||||||||
Other regulatory assets | 49 | 52 | (f) | |||||||||||||||||||||
Asset retirement obligations | (125 | ) | (132 | ) | (a) | |||||||||||||||||||
Other cost of removal obligations | (744 | ) | (828 | ) | (a) | |||||||||||||||||||
Deferred income tax credits | (72 | ) | (75 | ) | (a) | |||||||||||||||||||
Fuel-hedging gains | (1 | ) | (8 | ) | (e) | |||||||||||||||||||
Nuclear outage | 56 | 51 | (d) | |||||||||||||||||||||
Natural disaster reserve | (84 | ) | (96 | ) | (h) | |||||||||||||||||||
Other regulatory liabilities | (8 | ) | (11 | ) | (d,g) | |||||||||||||||||||
Retiree benefit plans | 882 | 461 | (i,j) | |||||||||||||||||||||
Regulatory deferrals | 13 | 20 | (l) | |||||||||||||||||||||
Nuclear fuel disposal fee | (8 | ) | — | (m) | ||||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 738 | $ | 92 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(b) | Recovered over the remaining life of the original issue, which may range up to 50 years. | |||||||||||||||||||||||
(c) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(d) | Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years. | |||||||||||||||||||||||
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||||||||||||||||||
(f) | Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. | |||||||||||||||||||||||
(g) | Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. | |||||||||||||||||||||||
(h) | Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. | |||||||||||||||||||||||
(i) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | |||||||||||||||||||||||
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(k) | Included in the deferred income tax charges are $18 million for 2014 and $20 million for 2013 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. | |||||||||||||||||||||||
(l) | Recorded and amortized as approved by the Alabama PSC for a period of five years. | |||||||||||||||||||||||
(m) | Recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The term of deferral is conditional upon resolution by the DOE. See Note 3 for additional information. | |||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP" for additional information. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | ||||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. | ||||||||||||||||||||||||
See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee Accounting Order" for additional information. | ||||||||||||||||||||||||
Income and Other Taxes | ||||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | ||||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 11,670 | $ | 11,314 | ||||||||||||||||||||
Transmission | 3,579 | 3,287 | ||||||||||||||||||||||
Distribution | 6,196 | 5,934 | ||||||||||||||||||||||
General | 1,623 | 1,545 | ||||||||||||||||||||||
Plant acquisition adjustment | 12 | 12 | ||||||||||||||||||||||
Total plant in service | $ | 23,080 | $ | 22,092 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. | ||||||||||||||||||||||||
Nuclear Outage Accounting Order | ||||||||||||||||||||||||
In accordance with an Alabama PSC order, nuclear outage operations and maintenance expenses for the two units at Plant Farley are deferred to a regulatory asset when the charges actually occur and are then amortized over a subsequent 18-month period with the fall outage costs amortization beginning in January of the following year and the spring outage costs amortization beginning in July of the same year. | ||||||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2014 and 3.2% in 2013 and 2012. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. | ||||||||||||||||||||||||
In 2014, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2015. The study was also provided to the Alabama PSC. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | ||||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 730 | $ | 589 | ||||||||||||||||||||
Liabilities incurred | 1 | — | ||||||||||||||||||||||
Liabilities settled | (3 | ) | (1 | ) | ||||||||||||||||||||
Accretion | 45 | 40 | ||||||||||||||||||||||
Cash flow revisions | 56 | 102 | ||||||||||||||||||||||
Balance at end of year | $ | 829 | $ | 730 | ||||||||||||||||||||
The cash flow revisions in 2014 are primarily related to the Company's AROs associated with asbestos at its steam generation facilities. The cash flow revisions in 2013 are primarily related to revisions to the nuclear decommissioning ARO based on the Company's updated decommissioning study. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $311 million and ongoing post-closure care of approximately $49 million. The Company will record AROs for the estimated closure costs required under the CCR Rule during 2015. SEGCO, which is jointly owned with Georgia Power, will also record an ARO for ash ponds commonly used at Plant E.C. Gaston. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Nuclear Decommissioning | ||||||||||||||||||||||||
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. | ||||||||||||||||||||||||
The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. | ||||||||||||||||||||||||
At December 31, 2014, investment securities in the Funds totaled $754 million, consisting of equity securities of $583 million, debt securities of $163 million, and $8 million of other securities. At December 31, 2013, investment securities in the Funds totaled $713 million, consisting of equity securities of $566 million, debt securities of $131 million, and $16 million of other securities. These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases. | ||||||||||||||||||||||||
Sales of the securities held in the Funds resulted in cash proceeds of $244 million, $279 million, and $193 million in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $54 million, of which $2 million related to realized gains and $19 million related to unrealized gains related to securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million, of which $5 million related to realized gains and $85 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $70 million, of which $4 million related to realized gains and $50 million related to unrealized losses related to securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. | ||||||||||||||||||||||||
Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. | ||||||||||||||||||||||||
At December 31, the accumulated provisions for decommissioning were as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
External trust funds | $ | 754 | $ | 713 | ||||||||||||||||||||
Internal reserves | 21 | 21 | ||||||||||||||||||||||
Total | $ | 775 | 734 | |||||||||||||||||||||
Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2014 based on the most current study performed in 2013 for Plant Farley are as follows: | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2037 | |||||||||||||||||||||||
Completion year | 2076 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 1,362 | ||||||||||||||||||||||
Non-radiated structures | 80 | |||||||||||||||||||||||
Total site study costs | $ | 1,442 | ||||||||||||||||||||||
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. | ||||||||||||||||||||||||
For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be conducted in 2018. | ||||||||||||||||||||||||
Amounts previously contributed to the Funds are currently projected to be adequate to meet the decommissioning obligations. The Company will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction | ||||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.8% in 2014, 9.1% in 2013, and 9.4% in 2012. AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 7.9% in 2014, 5.4% in 2013, and 3.3% in 2012. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | ||||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Cash and Cash Equivalents | ||||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | ||||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | ||||||||||||||||||||||||
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | ||||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | ||||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Variable Interest Entities | ||||||||||||||||||||||||
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. | ||||||||||||||||||||||||
The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in the balance sheets. | ||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||||||||||||||||
General | ||||||||||||||||||||||||
Georgia Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle. | ||||||||||||||||||||||||
The equity method is used for subsidiaries in which the Company has significant influence but does not control. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Georgia PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | ||||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $555 million in 2014, $504 million in 2013, and $540 million in 2012. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business, operations, and construction management. Costs for these services amounted to $643 million in 2014, $555 million in 2013, and $574 million in 2012. | ||||||||||||||||||||||||
The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $144 million, $136 million, and $147 million in 2014, 2013, and 2012, respectively. Additionally, the Company had $15 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2014 and 2013. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
The Company has a joint ownership agreement with Gulf Power under which Gulf Power owns a 25% portion of Plant Scherer Unit 3. Under this agreement, the Company operates Plant Scherer Unit 3 and Gulf Power reimburses the Company for its 25% proportionate share of the related non-fuel expenses, which were $9 million in 2014, $10 million in 2013, and $7 million in 2012. See Note 4 for additional information. | ||||||||||||||||||||||||
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014, 2013, or 2012. | ||||||||||||||||||||||||
The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | ||||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Retiree benefit plans | $ | 1,325 | $ | 691 | (a, j) | |||||||||||||||||||
Deferred income tax charges | 668 | 684 | (b, j) | |||||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 34 | 38 | (c) | |||||||||||||||||||||
Loss on reacquired debt | 163 | 181 | (d, j) | |||||||||||||||||||||
Asset retirement obligations | 108 | 137 | (b, j) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 29 | 22 | (e, j) | |||||||||||||||||||||
Vacation pay | 91 | 88 | (f, j) | |||||||||||||||||||||
Building lease | 31 | 37 | (g, j) | |||||||||||||||||||||
Cancelled construction projects | 67 | 70 | (h) | |||||||||||||||||||||
Remaining net book value of retired units | 25 | 28 | (i) | |||||||||||||||||||||
Storm damage reserves | 98 | 37 | (c) | |||||||||||||||||||||
Other regulatory assets | 63 | 49 | (c) | |||||||||||||||||||||
Other cost of removal obligations | (60 | ) | (58 | ) | (b) | |||||||||||||||||||
Deferred income tax credits | (106 | ) | (112 | ) | (b, j) | |||||||||||||||||||
Other regulatory liabilities | (7 | ) | (6 | ) | (e, j) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 2,529 | $ | 1,886 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the remaining two-year period of January 2015 through December 2016 in accordance with the Company's 2013 ARP. | |||||||||||||||||||||||
(c) | Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding eight years. | |||||||||||||||||||||||
(d) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 38 years. | |||||||||||||||||||||||
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism. | |||||||||||||||||||||||
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(g) | See Note 6 under "Capital Leases." Recovered over the remaining life of the building through 2020. | |||||||||||||||||||||||
(h) | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||||||||||||||||||
(i) | Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2022. | |||||||||||||||||||||||
(j) | Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | ||||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel. See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee" for additional information. | ||||||||||||||||||||||||
Income and Other Taxes | ||||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
Federal ITCs utilized are deferred and amortized to income as a credit to reduce depreciation over the average life of the related property. State ITCs are recognized in the period in which the credits are claimed on the state income tax return. A portion of the ITCs available to reduce income taxes payable was not utilized currently and will be carried forward and utilized in future years. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | ||||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the cost of equity and debt funds used during construction. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 15,201 | $ | 14,872 | ||||||||||||||||||||
Transmission | 5,086 | 4,859 | ||||||||||||||||||||||
Distribution | 8,913 | 8,620 | ||||||||||||||||||||||
General | 1,855 | 1,753 | ||||||||||||||||||||||
Plant acquisition adjustment | 28 | 28 | ||||||||||||||||||||||
Total plant in service | $ | 31,083 | $ | 30,132 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit's operating cycle. The refueling cycles are 18 and 24 months for Plant Vogtle Units 1 and 2 and Plant Hatch Units 1 and 2, respectively. | ||||||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.7% in 2014, 3.0% in 2013, and 2.9% in 2012. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. | ||||||||||||||||||||||||
In 2009, the Georgia PSC approved an accounting order allowing the Company to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of the Company's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), the Company amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $14 million is being amortized annually over the three years ending December 31, 2016. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | ||||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The ARO liability relates to the decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, as well as various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with the Company's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 1,222 | $ | 1,105 | ||||||||||||||||||||
Liabilities incurred | 9 | 2 | ||||||||||||||||||||||
Liabilities settled | (12 | ) | (13 | ) | ||||||||||||||||||||
Accretion | 53 | 55 | ||||||||||||||||||||||
Cash flow revisions | (17 | ) | 73 | |||||||||||||||||||||
Balance at end of year | $ | 1,255 | $ | 1,222 | ||||||||||||||||||||
The 2014 decrease in cash flow revisions is primarily related to settled AROs for asbestos remediation. The 2013 increase in cash flow revisions is related to updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units and revisions to the nuclear decommissioning AROs based on the latest decommissioning study. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $390 million and ongoing post-closure care of approximately $62 million. The Company has previously recorded AROs associated with ash ponds of $500 million, or $458 million on a nominal dollar basis, based on existing state requirements. During 2015, the Company will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Nuclear Decommissioning | ||||||||||||||||||||||||
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Georgia PSC, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. | ||||||||||||||||||||||||
The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. | ||||||||||||||||||||||||
The Funds participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2014 and 2013, approximately $51 million and $32 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $52 million and $33 million at December 31, 2014 and 2013, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows. | ||||||||||||||||||||||||
At December 31, 2014, investment securities in the Funds totaled $789 million, consisting of equity securities of $303 million, debt securities of $475 million, and $11 million of other securities. At December 31, 2013, investment securities in the Funds totaled $751 million, consisting of equity securities of $330 million, debt securities of $397 million, and $24 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases and the lending pool. | ||||||||||||||||||||||||
Sales of the securities held in the Funds resulted in cash proceeds of $669 million, $705 million, and $850 million in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $44 million, of which an immaterial amount related to unrealized gains and losses on securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $61 million, of which $34 million related to unrealized gains on securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $67 million, of which $25 million related to unrealized losses on securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. | ||||||||||||||||||||||||
The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. | ||||||||||||||||||||||||
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning are based on the most current study performed in 2012. The site study costs and external trust funds for decommissioning as of December 31, 2014 based on the Company's ownership interests were as follows: | ||||||||||||||||||||||||
Plant Hatch | Plant Vogtle | |||||||||||||||||||||||
Units 1 and 2 | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2034 | 2047 | ||||||||||||||||||||||
Completion year | 2068 | 2072 | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 549 | $ | 453 | ||||||||||||||||||||
Spent fuel management | 131 | 115 | ||||||||||||||||||||||
Non-radiated structures | 51 | 76 | ||||||||||||||||||||||
Total site study costs | $ | 731 | $ | 644 | ||||||||||||||||||||
External trust funds | $ | 496 | $ | 293 | ||||||||||||||||||||
For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4%. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction | ||||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2014, 2013, and 2012, the average AFUDC rates were 5.6%, 5.3%, and 6.8%, respectively, and AFUDC capitalized was $62 million, $44 million, and $75 million, respectively. AFUDC, net of income taxes, was 4.6%, 3.3%, and 5.7% of net income after dividends on preferred and preference stock for 2014, 2013, and 2012, respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to Plant Vogtle Units 3 and 4 in rate base effective January 1, 2011. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | ||||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Storm Damage Recovery | ||||||||||||||||||||||||
The Company defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $98 million and $37 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $68 million and $7 million included in other regulatory assets, deferred, respectively. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on the Company's financial statements. | ||||||||||||||||||||||||
Environmental Remediation Recovery | ||||||||||||||||||||||||
The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. In December 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff from 2014 through 2016. The Company recovered approximately $3 million annually through the ECCR tariff from 2011 through 2013 under the 2010 ARP. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, environmental remediation liabilities generally are not expected to have a material impact on the Company's financial statements. As of December 31, 2014, the balance of the environmental remediation liability was $22 million, with approximately $2 million included in other regulatory assets, current and approximately $14 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information. | ||||||||||||||||||||||||
Cash and Cash Equivalents | ||||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | ||||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | ||||||||||||||||||||||||
Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | ||||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | ||||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||||||||||||||||
General | ||||||||||||||||||||||||
Gulf Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
The equity method is used for entities in which the Company has significant influence but does not control. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Florida PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | ||||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $79.6 million, $78.4 million, and $95.9 million during 2014, 2013, and 2012, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $8.7 million, $10.2 million, and $6.9 million and Mississippi Power $30.5 million, $16.5 million, and $21.1 million in 2014, 2013, and 2012, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information. | ||||||||||||||||||||||||
The Company entered into a PPA with Southern Power for approximately 292 MWs annually from June 2009 through May 2014. Purchased power expenses associated with the PPA were $1.8 million, $14.2 million, and $14.7 million in 2014, 2013, and 2012, respectively, and fuel costs associated with the PPA were $1.7 million, $0.8 million, and $2.6 million in 2014, 2013, and 2012, respectively. These costs were approved for recovery by the Florida PSC through the Company's fuel and purchased power capacity cost recovery clauses. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
The Company had an agreement with Georgia Power under the transmission facility cost allocation tariff for delivery of power from the Company's resources in the state of Georgia. The Company reimbursed Georgia Power $1.0 million in 2014 and $2.4 million in each of the years 2013 and 2012 for its share of related expenses. | ||||||||||||||||||||||||
The Company has an agreement with Alabama Power under which Alabama Power has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA, which was entered into in 2009 for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. Revenue requirement obligations to Alabama Power for these upgrades are estimated to be $132.0 million for the entire project. These costs began in July 2012 and will continue through 2023. The Company reimbursed Alabama Power $11.9 million, $7.9 million, and $3.0 million in 2014, 2013, and 2012, respectively, for the revenue requirements. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff. | ||||||||||||||||||||||||
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014, 2013, or 2012. | ||||||||||||||||||||||||
The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | ||||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Deferred income tax charges | $ | 53,234 | $ | 47,573 | (a) | |||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 3,024 | 3,351 | (b) | |||||||||||||||||||||
Asset retirement obligations | (5,087 | ) | (6,089 | ) | (a,j) | |||||||||||||||||||
Other cost of removal obligations | (242,997 | ) | (228,148 | ) | (a) | |||||||||||||||||||
Regulatory asset, offset to other cost of removal | 8,410 | — | (m) | |||||||||||||||||||||
Deferred income tax credits | (3,872 | ) | (5,238 | ) | (a) | |||||||||||||||||||
Loss on reacquired debt | 15,991 | 16,565 | (c) | |||||||||||||||||||||
Vacation pay | 10,006 | 9,521 | (d,j) | |||||||||||||||||||||
Under recovered regulatory clause revenues | 52,619 | 45,191 | (e) | |||||||||||||||||||||
Property damage reserve | (35,111 | ) | (35,380 | ) | (f) | |||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 73,474 | 17,043 | (g,j) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) gains | (112 | ) | (6,962 | ) | (g,j) | |||||||||||||||||||
PPA charges | 185,065 | 180,149 | (j,k) | |||||||||||||||||||||
Other regulatory assets | 9,753 | 12,772 | (l) | |||||||||||||||||||||
Environmental remediation | 48,271 | 50,384 | (h,j) | |||||||||||||||||||||
Other regulatory liabilities | (649 | ) | (8,804 | ) | (f,j) | |||||||||||||||||||
Retiree benefit plans, net | 147,625 | 68,296 | (i,j) | |||||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 319,644 | $ | 160,224 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(b) | Recovered and amortized over periods not exceeding 14 years. | |||||||||||||||||||||||
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years. | |||||||||||||||||||||||
(d) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(e) | Recorded and recovered or amortized as approved by the Florida PSC, generally within one year. | |||||||||||||||||||||||
(f) | Recorded and recovered or amortized as approved by the Florida PSC. | |||||||||||||||||||||||
(g) | Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. | |||||||||||||||||||||||
(h) | Recovered through the environmental cost recovery clause when the remediation is performed. | |||||||||||||||||||||||
(i) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||||||||||||||||||
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(k) | Recovered over the life of the PPA for periods up to nine years. | |||||||||||||||||||||||
(l) | Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects. | |||||||||||||||||||||||
(m) Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013. See Note 3 for additional information. | ||||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | ||||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. | ||||||||||||||||||||||||
Income and Other Taxes | ||||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | ||||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Generation | $ | 2,637,817 | $ | 2,607,166 | ||||||||||||||||||||
Transmission | 515,754 | 473,378 | ||||||||||||||||||||||
Distribution | 1,156,872 | 1,117,024 | ||||||||||||||||||||||
General | 182,734 | 164,065 | ||||||||||||||||||||||
Plant acquisition adjustment | 1,776 | 2,031 | ||||||||||||||||||||||
Total plant in service | $ | 4,494,953 | $ | 4,363,664 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed. | ||||||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.6% in 2014, 2013, and 2012. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. As authorized by the Florida PSC in the settlement agreement approved in December 2013 (Settlement Agreement), the Company is allowed to reduce depreciation expense and record a regulatory asset in an aggregate amount up to $62.5 million between January 2014 and June 2017. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional information. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | ||||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The liability for AROs primarily relates to the Company's combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 16,184 | $ | 16,055 | ||||||||||||||||||||
Liabilities incurred | — | 518 | ||||||||||||||||||||||
Liabilities settled | (32 | ) | (1,913 | ) | ||||||||||||||||||||
Accretion | 718 | 751 | ||||||||||||||||||||||
Cash flow revisions | (159 | ) | 773 | |||||||||||||||||||||
Balance at end of year | $ | 16,711 | $ | 16,184 | ||||||||||||||||||||
The 2014 cash flow revisions are associated with asbestos and ash ponds at the Company's steam generation facilities. The 2013 cash flow revisions are associated with asbestos and an unloading dock at its generation facilities. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $62 million and ongoing post-closure care of approximately $11 million. The Company has previously recorded AROs associated with ash ponds of $6 million, or $11 million on a nominal dollar basis, based on existing state requirements. During 2015, the Company will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction | ||||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 5.73% for 2014, 6.26% for 2013, and 6.72% for 2012. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 10.93%, 6.87%, and 5.36% for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | ||||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Property Damage Reserve | ||||||||||||||||||||||||
The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $48.0 million and $55.0 million. The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2014, 2013, and 2012. As of December 31, 2014 and 2013, the balance in the Company's property damage reserve totaled approximately $35.7 million and $35.4 million, respectively, which is included in deferred liabilities in the balance sheets. | ||||||||||||||||||||||||
When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. In December 2013, the Florida PSC approved the Settlement Agreement that, among other things, provides for recovery of costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00/1,000 KWHs on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional details of the Settlement Agreement. | ||||||||||||||||||||||||
Injuries and Damages Reserve | ||||||||||||||||||||||||
The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2.0 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve was $4.0 million and $3.6 million at December 31, 2014 and 2013, respectively. For 2014, $1.6 million and $2.4 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. For 2013, $1.6 million and $2.0 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. There were no liabilities in excess of the reserve balance at December 31, 2014 or 2013. | ||||||||||||||||||||||||
Cash and Cash Equivalents | ||||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | ||||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | ||||||||||||||||||||||||
Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | ||||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 10 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | ||||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||||||||||||||||
General | ||||||||||||||||||||||||
Mississippi Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Mississippi PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | ||||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $259.0 million, $205.0 million, and $212.7 million during 2014, 2013, and 2012, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $13.4 million, $12.5 million, and $11.7 million in 2014, 2013, and 2012, respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility, which were $34.5 million, $27.1 million, and $28.1 million in 2014, 2013, and 2012, respectively. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs, which totaled $30.5 million, $16.5 million, and $21.2 million in 2014, 2013, and 2012, respectively. See Note 4 for additional information. | ||||||||||||||||||||||||
The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014 or 2013. The Company received storm assistance from other Southern Company subsidiaries totaling $2.0 million in 2012. | ||||||||||||||||||||||||
The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | ||||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Retiree benefit plans – regulatory assets | $ | 169,317 | $ | 82,799 | (a,g) | |||||||||||||||||||
Property damage | (61,648 | ) | (60,092 | ) | (i) | |||||||||||||||||||
Deferred income tax charges | 222,599 | 140,185 | (c) | |||||||||||||||||||||
Property tax | 27,680 | 31,206 | (d) | |||||||||||||||||||||
Vacation pay | 11,172 | 10,214 | (e,g) | |||||||||||||||||||||
Loss on reacquired debt | 8,542 | 9,178 | (k) | |||||||||||||||||||||
Plant Daniel Units 3 and 4 regulatory assets | 23,013 | 18,821 | (j) | |||||||||||||||||||||
Other regulatory assets | 16,270 | 5,415 | (b) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 46,631 | 10,340 | (f,g) | |||||||||||||||||||||
Asset retirement obligations | 10,845 | 8,918 | (c) | |||||||||||||||||||||
Deferred income tax credits | (9,370 | ) | (10,191 | ) | (c) | |||||||||||||||||||
Other cost of removal obligations | (165,999 | ) | (156,683 | ) | (c) | |||||||||||||||||||
Kemper IGCC regulatory assets | 147,689 | 75,873 | (h) | |||||||||||||||||||||
Mirror CWIP / Kemper regulatory deferral | (270,779 | ) | (90,524 | ) | (h) | |||||||||||||||||||
Other regulatory liabilities | (4,198 | ) | (8,855 | ) | (b) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 171,764 | $ | 66,604 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Recorded and recovered (amortized) as approved by the Mississippi PSC. | |||||||||||||||||||||||
(c) | Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(d) | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. | |||||||||||||||||||||||
(e) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(f) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the ECM. | |||||||||||||||||||||||
(g) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(h) | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||||||||||||||
(i) | For additional information, see Note 1 under "Provision for Property Damage." | |||||||||||||||||||||||
(j) | Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. | |||||||||||||||||||||||
(k) | Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years. | |||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income any regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Government Grants | ||||||||||||||||||||||||
In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270.0 million of the Kemper IGCC through the DOE Grants funds. Through December 31, 2014, the Company has received grant funds of $245.3 million, used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs. An additional $25 million is expected to be received for its initial operation. See Note 3 under "Kemper IGCC Schedule and Cost Estimate" for additional information. | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and projected amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery, ad valorem, and environmental factors annually. | ||||||||||||||||||||||||
The Company serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 21.9% of the Company's total operating revenues in 2014 and are largely subject to rolling 10-year cancellation notices. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Fuel Costs | ||||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC. | ||||||||||||||||||||||||
Income and Other Taxes | ||||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | ||||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of CWIP is not allowed in rates. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Generation | $ | 2,293,511 | $ | 1,475,264 | ||||||||||||||||||||
Transmission | 664,618 | 633,903 | ||||||||||||||||||||||
Distribution | 853,835 | 828,470 | ||||||||||||||||||||||
General | 484,711 | 439,721 | ||||||||||||||||||||||
Plant acquisition adjustment | 81,412 | 81,412 | ||||||||||||||||||||||
Total plant in service | $ | 4,378,087 | $ | 3,458,770 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses except for all costs associated with operating and maintaining the Kemper IGCC assets already placed in service and a portion of the railway track maintenance costs, which are charged to fuel stock and recovered through the Company's fuel clause or charged to regulatory assets to be recovered through rates over the life of the assets starting after the Kemper plant is placed in service. In addition, the cost of maintenance, repairs, and replacement of minor items of property for Kemper IGCC assets in service, excluding the lignite mine, are deferred in regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Depreciation, Depletion, and Amortization | ||||||||||||||||||||||||
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2014, 3.4% in 2013, and 3.5% in 2012. Depreciation studies are conducted periodically to update the composite rates. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities. | ||||||||||||||||||||||||
In January 2012, the Mississippi PSC issued an order allowing the Company to defer in a regulatory asset the difference between the revenue requirement under the purchase option of Plant Daniel Units 3 and 4 and the revenue requirement assuming operating lease accounting treatment for the extended term. The regulatory asset will be deferred for a 10-year period ending October 2021. At the conclusion of the deferral period, the unamortized deferral balance will be amortized into rates over the remaining life of the units. | ||||||||||||||||||||||||
The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. Depreciation associated with fixed assets, amortization associated with rolling stock, and depletion associated with minerals and minerals rights is recognized and charged to fuel stock and is expected to be recovered through the Company’s fuel clause. Depreciation associated with in-service Kemper IGCC-related assets has been deferred as a regulatory asset to be recovered over the life of the Kemper IGCC. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | ||||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The Company has AROs related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. | ||||||||||||||||||||||||
Details of the ARO included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 41,910 | $ | 42,115 | ||||||||||||||||||||
Liabilities settled | (2,529 | ) | (24 | ) | ||||||||||||||||||||
Accretion | 1,969 | 1,840 | ||||||||||||||||||||||
Cash flow revisions | 6,898 | (2,021 | ) | |||||||||||||||||||||
Balance at end of year | $ | 48,248 | $ | 41,910 | ||||||||||||||||||||
The increase in cash flow revisions in 2014 related to the Company's AROs associated with Watson landfill and Greene County asbestos. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $64 million and ongoing post-closure care of approximately $12 million. The Company will record AROs for the estimated closure costs required under the CCR Rule during 2015. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction | ||||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.91%, 6.89%, and 7.04% for the years ended December 31, 2014, 2013, and 2012, respectively. AFUDC equity was $136.4 million, $121.6 million, and $64.8 million in 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | ||||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. | ||||||||||||||||||||||||
Provision for Property Damage | ||||||||||||||||||||||||
The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every three years the Mississippi PSC, MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. In 2014, 2013, and 2012, the Company made retail accruals of $3.3 million, $3.2 million, and $3.5 million, respectively. The Company accrued $0.3 million annually in 2014, 2013, and 2012 for the wholesale jurisdiction. As of December 31, 2014, the property damage reserve balances were $60.7 million and $1.0 million for retail and wholesale, respectively. | ||||||||||||||||||||||||
Cash and Cash Equivalents | ||||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | ||||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as appropriate, at weighted-average cost when utilized. | ||||||||||||||||||||||||
Fuel Inventory | ||||||||||||||||||||||||
Fuel inventory includes the average cost of coal, lignite, natural gas, oil, transportation and emissions allowances. Fuel is charged to inventory when purchased, except for the cost of owning and operating the lignite mine related to the Kemper IGCC which is charged to inventory as incurred, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates or capitalized as part of the Kemper IGCC costs if used for testing. The retail rate is approved by the Mississippi PSC and the wholesale rates are approved by the FERC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | ||||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from the fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Fuel and interest rate derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Mississippi PSC approved fuel-hedging program as discussed below result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Foreign currency exchange rate hedges are designated as fair value hedges. Settled foreign currency exchange hedges are recorded in CWIP. Any ineffectiveness arising from these would be recognized currently in net income; however, the Company has regulatory approval allowing it to defer any ineffectiveness arising from hedging instruments relating to the Kemper IGCC to a regulatory asset. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of operations. The amounts related to derivatives on the cash flow statement are classified in the same category as the items being hedged. See Note 10 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | ||||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Variable Interest Entities | ||||||||||||||||||||||||
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. | ||||||||||||||||||||||||
The Company is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC, a subsidiary of North American Coal Corporation (Liberty Fuels), in conjunction with the construction of the Kemper IGCC. Liberty Fuels qualifies as a VIE for which the Company is the primary beneficiary. For the year ended December 31, 2014, the VIE consolidation resulted in an ARO asset and associated liability in the amounts of $21.0 million and $23.6 million, respectively. For the year ended December 31, 2013, the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21.0 million and $22.7 million, respectively. For the year ended December 31, 2012, the VIE consolidation resulted in an ARO and associated liability in the amounts of $21.0 million and $21.8 million, respectively. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |||||||||||||||||||||||
General | ||||||||||||||||||||||||
Southern Power Company is a wholly-owned subsidiary of The Southern Company (Southern Company), which is also the parent company of four traditional operating companies, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
Southern Power Company and certain of its generation subsidiaries are subject to regulation by the FERC. The Company follows GAAP. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. This includes an adjustment to the presentation of prepaid long-term service agreements (LTSA) to present amounts as noncurrent assets on the consolidated balance sheets. Prior period amounts recorded within other current assets have been reclassified to conform to the current presentation. See "Long-Term Service Agreements" herein for additional information. | ||||||||||||||||||||||||
The financial statements include the accounts of Southern Power Company and its wholly-owned subsidiaries, Southern Company – Florida, LLC, Oleander Power Project, LP, and Nacogdoches Power, LLC, which own, operate, and maintain the Company's ownership interests in Plants Stanton Unit A, Oleander, and Nacogdoches, respectively. The financial statements also include the accounts of Southern Power Company's wholly-owned subsidiaries, SRE and SRP. SRE and SRP were formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. Through STR, a jointly-owned subsidiary owned 90% by SRE and 10% by TRE, SRE and its subsidiaries own, operate, and maintain Plants Adobe, Apex, Campo Verde, Cimarron, Granville, Macho Springs, and Spectrum. Through SG2 Holdings, a jointly-owned subsidiary owned 51% by SRP and 49% by First Solar, SRP owns, operates, and maintains Plant Imperial Valley. All intercompany accounts and transactions have been eliminated in consolidation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | ||||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | ||||||||||||||||||||||||
Southern Power Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS amounted to approximately $125.9 million in 2014, $117.6 million in 2013, and $125.4 million in 2012. Of these costs, approximately $124.8 million in 2014, $114.3 million in 2013, and $107.7 million in 2012 were other operations and maintenance expenses; the remainder was recorded to plant in service. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has several agreements with SCS for transmission services. Transmission purchased from affiliates totaled $6.8 million in 2014, $8.3 million in 2013, and $6.6 million in 2012. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. | ||||||||||||||||||||||||
Total billings for all PPAs with affiliates were $156.4 million, $148.4 million, and $159.9 million in 2014, 2013, and 2012, respectively. Deferred amounts outstanding as of December 31 are included in the balance sheet as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Other deferred charges and assets - affiliated | $ | 2.9 | $ | 1.9 | ||||||||||||||||||||
Other current liabilities | — | (4.2 | ) | |||||||||||||||||||||
Deferred capacity revenues - affiliated | (15.3 | ) | (15.3 | ) | ||||||||||||||||||||
Total deferred amounts outstanding | $ | (12.4 | ) | $ | (17.6 | ) | ||||||||||||||||||
Revenue recognized under affiliate PPAs accounted for as operating leases totaled $74.8 million, $69.0 million, and $76.2 million in 2014, 2013, and 2012, respectively. The Company and the traditional operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. | ||||||||||||||||||||||||
The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. | ||||||||||||||||||||||||
Acquisition Accounting | ||||||||||||||||||||||||
The Company acquires generation assets as part of its overall growth strategy. The Company accounts for business acquisitions from non-affiliates as business combinations. Accordingly, the Company includes these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition is allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions are expensed as incurred. | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. | ||||||||||||||||||||||||
The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for further information. | ||||||||||||||||||||||||
Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. All revenues under solar PPAs are accounted for as contingent revenues and recognized as services are performed. Transmission revenues and other fees are recognized as earned as other operating revenues. Revenues are recorded on a gross basis for all full requirements PPAs. See "Financial Instruments" herein for additional information. | ||||||||||||||||||||||||
Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the top three customers: | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
FPL | 10.1 | % | 11.8 | % | 12.8 | % | ||||||||||||||||||
Georgia Power | 9.7 | % | 10.7 | % | 12.5 | % | ||||||||||||||||||
Duke Energy Corporation | 9.1 | % | 10.3 | % | 5.9 | % | ||||||||||||||||||
Fuel Costs | ||||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur. | ||||||||||||||||||||||||
Income and Other Taxes | ||||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. | ||||||||||||||||||||||||
Under the American Recovery and Reinvestment Act of 2009 (ARRA), and the American Taxpayer Relief Act of 2012 (ATRA), certain projects are eligible for federal ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $11.4 million, $5.5 million, and $2.6 million in 2014, 2013, and 2012, respectively. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. Federal and state ITCs available to reduce income taxes payable were not fully utilized during the year and will be carried forward and utilized in future years. See Note 5 under "Effective Tax Rate" for additional information. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | ||||||||||||||||||||||||
The Company's depreciable property, plant, and equipment consists entirely of generation assets. | ||||||||||||||||||||||||
Property, plant, and equipment is stated at original cost. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred. | ||||||||||||||||||||||||
Depreciation | ||||||||||||||||||||||||
Beginning in 2014, the Company changed to component depreciation, where the depreciation of the original cost of assets is computed principally by the straight-line method over the estimated useful lives of assets as determined by management. Certain generation assets are now depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. The primary assets in property, plant, and equipment are power plants, which have estimated useful lives ranging from 35 to 45 years. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. The book value of plant-in-service as of December 31, 2014 that is depreciated on a units-of-production basis was approximately $470.2 million. | ||||||||||||||||||||||||
When property subject to depreciation is retired or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. | ||||||||||||||||||||||||
Prior to 2014, the Company computed depreciation of the original cost of assets under the straight-line method and applied a composite depreciation rate based on the assets' estimated useful lives as determined by management. | ||||||||||||||||||||||||
Long-Term Service Agreements | ||||||||||||||||||||||||
The Company has entered into LTSAs for the purpose of securing maintenance support for substantially all of its generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. | ||||||||||||||||||||||||
Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in noncurrent assets on the balance sheets and are recorded as payments pursuant to LTSAs in the statements of cash flows. All work performed is capitalized or charged to expense as appropriate based on the nature of the work when performed; therefore, these charges are non-cash and are not reflected in the statements of cash flows. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | ||||||||||||||||||||||||
The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of these PPAs is 20 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
The amortization expense for the acquired PPAs for the years ended December 31, 2014, 2013, and 2012 was $2.5 million, $2.5 million, and $1.7 million, respectively, and the amortization for future periods is as follows: | ||||||||||||||||||||||||
Amortization | ||||||||||||||||||||||||
Expense | ||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
2015 | $ | 2.5 | ||||||||||||||||||||||
2016 | 2.4 | |||||||||||||||||||||||
2017 | 2.5 | |||||||||||||||||||||||
2018 | 2.5 | |||||||||||||||||||||||
2019 | 2.5 | |||||||||||||||||||||||
2020 and beyond | 28.5 | |||||||||||||||||||||||
Total | $ | 40.9 | ||||||||||||||||||||||
Emission Reduction Credits | ||||||||||||||||||||||||
The Company has acquired emission reduction credits necessary for future unspecified construction in areas designated by the EPA as non-attainment areas for nitrogen oxide or volatile organic compound emissions. These credits are reflected on the balance sheets at historical cost. The cost of emission reduction offsets to be surrendered are generally transferred to CWIP upon commencement of construction. The total emission reduction credits were $11.0 million at December 31, 2014 and 2013. | ||||||||||||||||||||||||
Cash and Cash Equivalents | ||||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | ||||||||||||||||||||||||
Generally, materials and supplies include the average cost of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | ||||||||||||||||||||||||
Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost. | ||||||||||||||||||||||||
Financial Instruments | ||||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions result in the deferral of related gains and losses in AOCI until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. See Note 9 for additional information regarding derivatives. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | ||||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications of amounts included in net income. | ||||||||||||||||||||||||
Variable Interest Entities | ||||||||||||||||||||||||
The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. | ||||||||||||||||||||||||
The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. |
Retirement_Benefits
Retirement Benefits | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||||||
RETIREMENT BENEFITS | RETIREMENT BENEFITS | |||||||||||||||
Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2014, certain of the traditional operating companies and other subsidiaries voluntarily contributed an aggregate of $500 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2015, other postretirement trust contributions are expected to total approximately $19 million. | ||||||||||||||||
Actuarial Assumptions | ||||||||||||||||
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%. | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.17 | % | 5.02 | % | 4.26 | % | ||||||||||
Other postretirement benefit plans | 4.04 | 4.85 | 4.05 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 7.15 | 7.13 | 7.29 | |||||||||||||
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. | ||||||||||||||||
For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $636 million and $92 million, respectively. | ||||||||||||||||
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | ||||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | ||||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in millions) | ||||||||||||||||
Benefit obligation | $ | 140 | $ | (117 | ) | |||||||||||
Service and interest costs | 6 | (5 | ) | |||||||||||||
Pension Plans | ||||||||||||||||
The total accumulated benefit obligation for the pension plans was $10.0 billion at December 31, 2014 and $8.1 billion at December 31, 2013. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 8,863 | $ | 9,302 | ||||||||||||
Service cost | 213 | 232 | ||||||||||||||
Interest cost | 435 | 389 | ||||||||||||||
Benefits paid | (382 | ) | (357 | ) | ||||||||||||
Actuarial (gain) loss | 1,780 | (703 | ) | |||||||||||||
Balance at end of year | 10,909 | 8,863 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 8,733 | 7,953 | ||||||||||||||
Actual return on plan assets | 797 | 1,098 | ||||||||||||||
Employer contributions | 542 | 39 | ||||||||||||||
Benefits paid | (382 | ) | (357 | ) | ||||||||||||
Fair value of plan assets at end of year | 9,690 | 8,733 | ||||||||||||||
Accrued liability | $ | (1,219 | ) | $ | (130 | ) | ||||||||||
At December 31, 2014, the projected benefit obligations for the qualified and non-qualified pension plans were $10.3 billion and $617 million, respectively. All pension plan assets are related to the qualified pension plan. | ||||||||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 419 | ||||||||||||
Other regulatory assets, deferred | 3,073 | 1,651 | ||||||||||||||
Other current liabilities | (42 | ) | (40 | ) | ||||||||||||
Employee benefit obligations | (1,177 | ) | (509 | ) | ||||||||||||
Accumulated OCI | 134 | 64 | ||||||||||||||
Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
Prior | Net (Gain) Loss | |||||||||||||||
Service | ||||||||||||||||
Cost | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2014: | ||||||||||||||||
Accumulated OCI | $ | 4 | $ | 130 | ||||||||||||
Regulatory assets | 51 | 3,022 | ||||||||||||||
Total | $ | 55 | $ | 3,152 | ||||||||||||
Balance at December 31, 2013: | ||||||||||||||||
Accumulated OCI | $ | 5 | $ | 59 | ||||||||||||
Regulatory assets | 75 | 1,575 | ||||||||||||||
Total | $ | 80 | $ | 1,634 | ||||||||||||
Estimated amortization in net periodic pension cost in 2015: | ||||||||||||||||
Accumulated OCI | $ | 1 | $ | 9 | ||||||||||||
Regulatory assets | 24 | 206 | ||||||||||||||
Total | $ | 25 | $ | 215 | ||||||||||||
The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
Accumulated | Regulatory Assets | |||||||||||||||
OCI | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2012 | $ | 125 | $ | 3,013 | ||||||||||||
Net gain | (52 | ) | (1,145 | ) | ||||||||||||
Change in prior service costs | — | 1 | ||||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1 | ) | (26 | ) | ||||||||||||
Amortization of net gain (loss) | (8 | ) | (192 | ) | ||||||||||||
Total reclassification adjustments | (9 | ) | (218 | ) | ||||||||||||
Total change | (61 | ) | (1,362 | ) | ||||||||||||
Balance at December 31, 2013 | $ | 64 | $ | 1,651 | ||||||||||||
Net gain | 75 | 1,552 | ||||||||||||||
Change in prior service costs | — | 1 | ||||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1 | ) | (25 | ) | ||||||||||||
Amortization of net gain (loss) | (4 | ) | (106 | ) | ||||||||||||
Total reclassification adjustments | (5 | ) | (131 | ) | ||||||||||||
Total change | 70 | 1,422 | ||||||||||||||
Balance at December 31, 2014 | $ | 134 | $ | 3,073 | ||||||||||||
Components of net periodic pension cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 213 | $ | 232 | $ | 198 | ||||||||||
Interest cost | 435 | 389 | 393 | |||||||||||||
Expected return on plan assets | (645 | ) | (603 | ) | (581 | ) | ||||||||||
Recognized net loss | 110 | 200 | 95 | |||||||||||||
Net amortization | 26 | 27 | 30 | |||||||||||||
Net periodic pension cost | $ | 139 | $ | 245 | $ | 135 | ||||||||||
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. | ||||||||||||||||
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2014, estimated benefit payments were as follows: | ||||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 522 | ||||||||||||||
2016 | 450 | |||||||||||||||
2017 | 478 | |||||||||||||||
2018 | 499 | |||||||||||||||
2019 | 524 | |||||||||||||||
2020 to 2024 | 2,962 | |||||||||||||||
Other Postretirement Benefits | ||||||||||||||||
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 1,682 | $ | 1,872 | ||||||||||||
Service cost | 21 | 24 | ||||||||||||||
Interest cost | 79 | 74 | ||||||||||||||
Benefits paid | (102 | ) | (94 | ) | ||||||||||||
Actuarial (gain) loss | 300 | (200 | ) | |||||||||||||
Plan amendments | (2 | ) | — | |||||||||||||
Retiree drug subsidy | 8 | 6 | ||||||||||||||
Balance at end of year | 1,986 | 1,682 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 901 | 821 | ||||||||||||||
Actual return on plan assets | 54 | 129 | ||||||||||||||
Employer contributions | 39 | 39 | ||||||||||||||
Benefits paid | (94 | ) | (88 | ) | ||||||||||||
Fair value of plan assets at end of year | 900 | 901 | ||||||||||||||
Accrued liability | $ | (1,086 | ) | $ | (781 | ) | ||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Other regulatory assets, deferred | $ | 387 | $ | 109 | ||||||||||||
Other current liabilities | (4 | ) | (4 | ) | ||||||||||||
Employee benefit obligations | (1,082 | ) | (777 | ) | ||||||||||||
Other regulatory liabilities, deferred | (21 | ) | (36 | ) | ||||||||||||
Accumulated OCI | 8 | 1 | ||||||||||||||
Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
Prior | Net (Gain) | |||||||||||||||
Service | Loss | |||||||||||||||
Cost | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2014: | ||||||||||||||||
Accumulated OCI | $ | — | $ | 8 | ||||||||||||
Net regulatory assets (liabilities) | 2 | 364 | ||||||||||||||
Total | $ | 2 | $ | 372 | ||||||||||||
Balance at December 31, 2013: | ||||||||||||||||
Accumulated OCI | $ | — | $ | 1 | ||||||||||||
Net regulatory assets (liabilities) | 9 | 64 | ||||||||||||||
Total | $ | 9 | $ | 65 | ||||||||||||
Estimated amortization as net periodic postretirement benefit cost in 2015: | ||||||||||||||||
Accumulated OCI | $ | — | $ | — | ||||||||||||
Net regulatory assets (liabilities) | 4 | 17 | ||||||||||||||
Total | $ | 4 | $ | 17 | ||||||||||||
The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
Accumulated | Net Regulatory | |||||||||||||||
OCI | Assets | |||||||||||||||
(Liabilities) | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2012 | $ | 7 | $ | 360 | ||||||||||||
Net loss | (6 | ) | (266 | ) | ||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of transition obligation | — | (5 | ) | |||||||||||||
Amortization of prior service costs | — | (4 | ) | |||||||||||||
Amortization of net gain (loss) | — | (12 | ) | |||||||||||||
Total reclassification adjustments | — | (21 | ) | |||||||||||||
Total change | (6 | ) | (287 | ) | ||||||||||||
Balance at December 31, 2013 | $ | 1 | $ | 73 | ||||||||||||
Net gain | 7 | 301 | ||||||||||||||
Change in prior service costs | — | (2 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | — | (4 | ) | |||||||||||||
Amortization of net gain (loss) | — | (2 | ) | |||||||||||||
Total reclassification adjustments | — | (6 | ) | |||||||||||||
Total change | 7 | 293 | ||||||||||||||
Balance at December 31, 2014 | $ | 8 | $ | 366 | ||||||||||||
Components of the other postretirement benefit plans' net periodic cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 21 | $ | 24 | $ | 21 | ||||||||||
Interest cost | 79 | 74 | 85 | |||||||||||||
Expected return on plan assets | (59 | ) | (56 | ) | (60 | ) | ||||||||||
Net amortization | 6 | 21 | 20 | |||||||||||||
Net periodic postretirement benefit cost | $ | 47 | $ | 63 | $ | 66 | ||||||||||
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | ||||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 118 | $ | (10 | ) | $ | 108 | |||||||||
2016 | 124 | (11 | ) | 113 | ||||||||||||
2017 | 129 | (12 | ) | 117 | ||||||||||||
2018 | 132 | (13 | ) | 119 | ||||||||||||
2019 | 134 | (15 | ) | 119 | ||||||||||||
2020 to 2024 | 670 | (79 | ) | 591 | ||||||||||||
Benefit Plan Assets | ||||||||||||||||
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. | ||||||||||||||||
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | ||||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 42 | % | 41 | % | 40 | % | ||||||||||
International equity | 21 | 23 | 25 | |||||||||||||
Domestic fixed income | 24 | 26 | 24 | |||||||||||||
Global fixed income | 4 | 3 | 4 | |||||||||||||
Special situations | 1 | — | — | |||||||||||||
Real estate investments | 5 | 5 | 5 | |||||||||||||
Private equity | 3 | 2 | 2 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. | ||||||||||||||||
Investment Strategies | ||||||||||||||||
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: | ||||||||||||||||
• | Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. | |||||||||||||||
• | International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | |||||||||||||||
• | Fixed income. A mix of domestic and international bonds. | |||||||||||||||
• | Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. | |||||||||||||||
• | Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. | |||||||||||||||
• | Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. | |||||||||||||||
• | Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | |||||||||||||||
Benefit Plan Asset Fair Values | ||||||||||||||||
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2014 and 2013. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. | ||||||||||||||||
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: | ||||||||||||||||
• | Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. | |||||||||||||||
• | Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. | |||||||||||||||
• | TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. | |||||||||||||||
• | Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. | |||||||||||||||
The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 1,704 | $ | 704 | $ | — | $ | 2,408 | ||||||||
International equity* | 1,070 | 986 | — | 2,056 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 699 | — | 699 | ||||||||||||
Mortgage- and asset-backed securities | — | 188 | — | 188 | ||||||||||||
Corporate bonds | — | 1,135 | — | 1,135 | ||||||||||||
Pooled funds | — | 514 | — | 514 | ||||||||||||
Cash equivalents and other | 3 | 660 | — | 663 | ||||||||||||
Real estate investments | 293 | — | 1,121 | 1,414 | ||||||||||||
Private equity | — | — | 570 | 570 | ||||||||||||
Total | $ | 3,070 | $ | 4,886 | $ | 1,691 | $ | 9,647 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (2 | ) | $ | — | $ | — | $ | (2 | ) | ||||||
Total | $ | 3,068 | $ | 4,886 | $ | 1,691 | $ | 9,645 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 1,433 | $ | 839 | $ | — | $ | 2,272 | ||||||||
International equity* | 1,101 | 1,018 | — | 2,119 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 599 | — | 599 | ||||||||||||
Mortgage- and asset-backed securities | — | 156 | — | 156 | ||||||||||||
Corporate bonds | — | 978 | — | 978 | ||||||||||||
Pooled funds | — | 471 | — | 471 | ||||||||||||
Cash equivalents and other | 1 | 223 | — | 224 | ||||||||||||
Real estate investments | 260 | — | 1,000 | 1,260 | ||||||||||||
Private equity | — | — | 571 | 571 | ||||||||||||
Total | $ | 2,795 | $ | 4,284 | $ | 1,571 | $ | 8,650 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (3 | ) | $ | — | $ | (3 | ) | ||||||
Total | $ | 2,795 | $ | 4,281 | $ | 1,571 | $ | 8,647 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 1,000 | $ | 571 | $ | 841 | $ | 593 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 79 | 51 | 74 | 8 | ||||||||||||
Related to investments sold during the year | 33 | (16 | ) | 30 | 51 | |||||||||||
Total return on investments | 112 | 35 | 104 | 59 | ||||||||||||
Purchases, sales, and settlements | 9 | (36 | ) | 55 | (81 | ) | ||||||||||
Ending balance | $ | 1,121 | $ | 570 | $ | 1,000 | $ | 571 | ||||||||
The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | Total | |||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | |||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 147 | $ | 56 | $ | — | $ | 203 | ||||||||
International equity* | 36 | 67 | — | 103 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 29 | — | 29 | ||||||||||||
Mortgage- and asset-backed securities | — | 6 | — | 6 | ||||||||||||
Corporate bonds | — | 39 | — | 39 | ||||||||||||
Pooled funds | — | 41 | — | 41 | ||||||||||||
Cash equivalents and other | 9 | 27 | — | 36 | ||||||||||||
Trust-owned life insurance | — | 381 | — | 381 | ||||||||||||
Real estate investments | 11 | — | 37 | 48 | ||||||||||||
Private equity | — | — | 19 | 19 | ||||||||||||
Total | $ | 203 | $ | 646 | $ | 56 | $ | 905 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 157 | $ | 45 | $ | — | $ | 202 | ||||||||
International equity* | 39 | 82 | — | 121 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 34 | — | 34 | ||||||||||||
Mortgage- and asset-backed securities | — | 6 | — | 6 | ||||||||||||
Corporate bonds | — | 35 | — | 35 | ||||||||||||
Pooled funds | — | 46 | — | 46 | ||||||||||||
Cash equivalents and other | — | 19 | — | 19 | ||||||||||||
Trust-owned life insurance | — | 369 | — | 369 | ||||||||||||
Real estate investments | 10 | — | 36 | 46 | ||||||||||||
Private equity | — | — | 20 | 20 | ||||||||||||
Total | $ | 206 | $ | 636 | $ | 56 | $ | 898 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 36 | $ | 20 | $ | 30 | $ | 21 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 1 | 1 | 3 | — | ||||||||||||
Related to investments sold during the year | — | (1 | ) | 1 | 2 | |||||||||||
Total return on investments | 1 | — | 4 | 2 | ||||||||||||
Purchases, sales, and settlements | — | (1 | ) | 2 | (3 | ) | ||||||||||
Ending balance | $ | 37 | $ | 19 | $ | 36 | $ | 20 | ||||||||
Employee Savings Plan | ||||||||||||||||
Southern Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2014, 2013, and 2012 were $87 million, $84 million, and $82 million, respectively. | ||||||||||||||||
Alabama Power [Member] | ||||||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||||||
RETIREMENT BENEFITS | RETIREMENT BENEFITS | |||||||||||||||
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions were made to the qualified pension plan during 2014. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Alabama PSC and the FERC. For the year ending December 31, 2015, other postretirement trusts contributions are expected to total approximately $2 million. | ||||||||||||||||
Actuarial Assumptions | ||||||||||||||||
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%. | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.18 | % | 5.02 | % | 4.27 | % | ||||||||||
Other postretirement benefit plans | 4.04 | 4.86 | 4.06 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 7.34 | 7.36 | 7.19 | |||||||||||||
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. | ||||||||||||||||
For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $156 million and $22 million, respectively. | ||||||||||||||||
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | ||||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | ||||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in millions) | ||||||||||||||||
Benefit obligation | $ | 34 | $ | (29 | ) | |||||||||||
Service and interest costs | 1 | (1 | ) | |||||||||||||
Pension Plans | ||||||||||||||||
The total accumulated benefit obligation for the pension plans was $2.4 billion at December 31, 2014 and $1.9 billion at December 31, 2013. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 2,112 | $ | 2,218 | ||||||||||||
Service cost | 48 | 52 | ||||||||||||||
Interest cost | 103 | 93 | ||||||||||||||
Benefits paid | (100 | ) | (93 | ) | ||||||||||||
Actuarial (gain) loss | 429 | (158 | ) | |||||||||||||
Balance at end of year | 2,592 | 2,112 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 2,278 | 2,077 | ||||||||||||||
Actual return on plan assets | 207 | 285 | ||||||||||||||
Employer contributions | 11 | 9 | ||||||||||||||
Benefits paid | (100 | ) | (93 | ) | ||||||||||||
Fair value of plan assets at end of year | 2,396 | 2,278 | ||||||||||||||
Prepaid pension costs (accrued liability) | $ | (196 | ) | $ | 166 | |||||||||||
At December 31, 2014, the projected benefit obligations for the qualified and non-qualified pension plans were $2.5 billion and $123 million, respectively. All pension plan assets are related to the qualified pension plan. | ||||||||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 276 | ||||||||||||
Other regulatory assets, deferred | 827 | 476 | ||||||||||||||
Other current liabilities | (10 | ) | (9 | ) | ||||||||||||
Employee benefit obligations | (186 | ) | (101 | ) | ||||||||||||
Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | 12 | $ | 19 | $ | 6 | ||||||||||
Net (gain) loss | 815 | 457 | 55 | |||||||||||||
Regulatory assets | $ | 827 | $ | 476 | ||||||||||||
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 476 | $ | 822 | ||||||||||||
Net (gain) loss | 389 | (287 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (7 | ) | (7 | ) | ||||||||||||
Amortization of net gain (loss) | (31 | ) | (52 | ) | ||||||||||||
Total reclassification adjustments | (38 | ) | (59 | ) | ||||||||||||
Total change | 351 | (346 | ) | |||||||||||||
Ending balance | $ | 827 | $ | 476 | ||||||||||||
Components of net periodic pension cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 48 | $ | 52 | $ | 44 | ||||||||||
Interest cost | 103 | 93 | 94 | |||||||||||||
Expected return on plan assets | (168 | ) | (157 | ) | (162 | ) | ||||||||||
Recognized net (gain) loss | 31 | 52 | 23 | |||||||||||||
Net amortization | 7 | 7 | 7 | |||||||||||||
Net periodic pension cost | $ | 21 | $ | 47 | $ | 6 | ||||||||||
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. | ||||||||||||||||
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2014, estimated benefit payments were as follows: | ||||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 127 | ||||||||||||||
2016 | 114 | |||||||||||||||
2017 | 120 | |||||||||||||||
2018 | 125 | |||||||||||||||
2019 | 129 | |||||||||||||||
2020 to 2024 | 708 | |||||||||||||||
Other Postretirement Benefits | ||||||||||||||||
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 431 | $ | 490 | ||||||||||||
Service cost | 5 | 6 | ||||||||||||||
Interest cost | 20 | 19 | ||||||||||||||
Benefits paid | (27 | ) | (24 | ) | ||||||||||||
Actuarial (gain) loss | 71 | (62 | ) | |||||||||||||
Retiree drug subsidy | 3 | 2 | ||||||||||||||
Balance at end of year | 503 | 431 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 389 | 343 | ||||||||||||||
Actual return on plan assets | 23 | 61 | ||||||||||||||
Employer contributions | 4 | 7 | ||||||||||||||
Benefits paid | (24 | ) | (22 | ) | ||||||||||||
Fair value of plan assets at end of year | 392 | 389 | ||||||||||||||
Accrued liability | $ | (111 | ) | $ | (42 | ) | ||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Other regulatory assets, deferred | $ | 68 | $ | 6 | ||||||||||||
Other regulatory liabilities, deferred | (14 | ) | (21 | ) | ||||||||||||
Employee benefit obligations | (111 | ) | (42 | ) | ||||||||||||
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | 15 | $ | 19 | $ | 4 | ||||||||||
Net (gain) loss | 39 | (34 | ) | 2 | ||||||||||||
Net regulatory assets (liabilities) | $ | 54 | $ | (15 | ) | |||||||||||
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Net regulatory assets (liabilities): | ||||||||||||||||
Beginning balance | $ | (15 | ) | $ | 89 | |||||||||||
Net gain (loss) | 73 | (99 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (4 | ) | (3 | ) | ||||||||||||
Amortization of net gain (loss) | — | (2 | ) | |||||||||||||
Total reclassification adjustments | (4 | ) | (5 | ) | ||||||||||||
Total change | 69 | (104 | ) | |||||||||||||
Ending balance | $ | 54 | $ | (15 | ) | |||||||||||
Components of the other postretirement benefit plans' net periodic cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 5 | $ | 6 | $ | 5 | ||||||||||
Interest cost | 20 | 19 | 22 | |||||||||||||
Expected return on plan assets | (25 | ) | (23 | ) | (23 | ) | ||||||||||
Net amortization | 4 | 5 | 6 | |||||||||||||
Net periodic postretirement benefit cost | $ | 4 | $ | 7 | $ | 10 | ||||||||||
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | ||||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 31 | $ | (3 | ) | $ | 28 | |||||||||
2016 | 32 | (3 | ) | 29 | ||||||||||||
2017 | 32 | (4 | ) | 28 | ||||||||||||
2018 | 34 | (4 | ) | 30 | ||||||||||||
2019 | 34 | (4 | ) | 30 | ||||||||||||
2020 to 2024 | 172 | (22 | ) | 150 | ||||||||||||
Benefit Plan Assets | ||||||||||||||||
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. | ||||||||||||||||
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | ||||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 48 | % | 48 | % | 47 | % | ||||||||||
International equity | 20 | 20 | 20 | |||||||||||||
Domestic fixed income | 24 | 26 | 27 | |||||||||||||
Special situations | 1 | — | — | |||||||||||||
Real estate investments | 4 | 4 | 4 | |||||||||||||
Private equity | 3 | 2 | 2 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. | ||||||||||||||||
Investment Strategies | ||||||||||||||||
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: | ||||||||||||||||
• | Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. | |||||||||||||||
• | International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | |||||||||||||||
• | Fixed income. A mix of domestic and international bonds. | |||||||||||||||
• | Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. | |||||||||||||||
• | Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. | |||||||||||||||
• | Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. | |||||||||||||||
• | Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | |||||||||||||||
Benefit Plan Asset Fair Values | ||||||||||||||||
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2014 and 2013. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. | ||||||||||||||||
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: | ||||||||||||||||
• | Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. | |||||||||||||||
• | Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. | |||||||||||||||
• | TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. | |||||||||||||||
• | Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. | |||||||||||||||
The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
in Active Markets for Identical Assets | ||||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 421 | $ | 174 | $ | — | $ | 595 | ||||||||
International equity* | 264 | 244 | — | 508 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 173 | — | 173 | ||||||||||||
Mortgage- and asset-backed securities | — | 47 | — | 47 | ||||||||||||
Corporate bonds | — | 280 | — | 280 | ||||||||||||
Pooled funds | — | 127 | — | 127 | ||||||||||||
Cash equivalents and other | 1 | 163 | — | 164 | ||||||||||||
Real estate investments | 73 | — | 277 | 350 | ||||||||||||
Private equity | — | — | 141 | 141 | ||||||||||||
Total | $ | 759 | $ | 1,208 | $ | 418 | $ | 2,385 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
in Active Markets for Identical Assets | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 374 | $ | 219 | $ | — | $ | 593 | ||||||||
International equity* | 287 | 265 | — | 552 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 156 | — | 156 | ||||||||||||
Mortgage- and asset-backed securities | — | 41 | — | 41 | ||||||||||||
Corporate bonds | — | 255 | — | 255 | ||||||||||||
Pooled funds | — | 123 | — | 123 | ||||||||||||
Cash equivalents and other | — | 58 | — | 58 | ||||||||||||
Real estate investments | 68 | — | 261 | 329 | ||||||||||||
Private equity | — | — | 149 | 149 | ||||||||||||
Total | $ | 729 | $ | 1,117 | $ | 410 | $ | 2,256 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | ||||||
Total | $ | 729 | $ | 1,116 | $ | 410 | $ | 2,255 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 261 | $ | 149 | $ | 220 | $ | 155 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 6 | 5 | 19 | 2 | ||||||||||||
Related to investments sold during the year | 8 | (4 | ) | 8 | 13 | |||||||||||
Total return on investments | 14 | 1 | 27 | 15 | ||||||||||||
Purchases, sales, and settlements | 2 | (9 | ) | 14 | (21 | ) | ||||||||||
Ending balance | $ | 277 | $ | 141 | $ | 261 | $ | 149 | ||||||||
The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 76 | $ | 8 | $ | — | $ | 84 | ||||||||
International equity* | 13 | 12 | — | 25 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 10 | — | 10 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 14 | — | 14 | ||||||||||||
Pooled funds | — | 6 | — | 6 | ||||||||||||
Cash equivalents and other | — | 8 | — | 8 | ||||||||||||
Trust-owned life insurance | — | 217 | — | 217 | ||||||||||||
Real estate investments | 5 | — | 13 | 18 | ||||||||||||
Private equity | — | — | 7 | 7 | ||||||||||||
Total | $ | 94 | $ | 277 | $ | 20 | $ | 391 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 67 | $ | 11 | $ | — | $ | 78 | ||||||||
International equity* | 14 | 13 | — | 27 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 17 | — | 17 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 12 | — | 12 | ||||||||||||
Pooled funds | — | 6 | — | 6 | ||||||||||||
Cash equivalents and other | — | 10 | — | 10 | ||||||||||||
Trust-owned life insurance | — | 211 | — | 211 | ||||||||||||
Real estate investments | 4 | — | 13 | 17 | ||||||||||||
Private equity | — | — | 7 | 7 | ||||||||||||
Total | $ | 85 | $ | 282 | $ | 20 | $ | 387 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 13 | $ | 7 | $ | 11 | $ | 8 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | — | — | 1 | — | ||||||||||||
Related to investments sold during the year | — | — | — | — | ||||||||||||
Total return on investments | — | — | 1 | — | ||||||||||||
Purchases, sales, and settlements | — | — | 1 | (1 | ) | |||||||||||
Ending balance | $ | 13 | $ | 7 | $ | 13 | $ | 7 | ||||||||
Employee Savings Plan | ||||||||||||||||
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2014, 2013, and 2012 were $21 million, $20 million, and $19 million, respectively. | ||||||||||||||||
Georgia Power [Member] | ||||||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||||||
RETIREMENT BENEFITS | RETIREMENT BENEFITS | |||||||||||||||
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2014, the Company voluntarily contributed $150 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the Georgia PSC and the FERC. For the year ending December 31, 2015, other postretirement trust contributions are expected to total approximately $17 million. | ||||||||||||||||
Actuarial Assumptions | ||||||||||||||||
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.87%, respectively, and an annual salary increase of 3.84%. | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.18 | % | 5.02 | % | 4.27 | % | ||||||||||
Other postretirement benefit plans | 4.03 | 4.85 | 4.04 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 6.75 | 6.74 | 7.24 | |||||||||||||
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. | ||||||||||||||||
For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $226 million and $46 million, respectively. | ||||||||||||||||
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | ||||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | ||||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in millions) | ||||||||||||||||
Benefit obligation | $ | 69 | $ | (58 | ) | |||||||||||
Service and interest costs | 3 | (2 | ) | |||||||||||||
Pension Plans | ||||||||||||||||
The total accumulated benefit obligation for the pension plans was $3.5 billion at December 31, 2014 and $2.9 billion at December 31, 2013. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 3,116 | $ | 3,312 | ||||||||||||
Service cost | 62 | 69 | ||||||||||||||
Interest cost | 153 | 138 | ||||||||||||||
Benefits paid | (149 | ) | (141 | ) | ||||||||||||
Actuarial (gain) loss | 599 | (262 | ) | |||||||||||||
Balance at end of year | 3,781 | 3,116 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 3,085 | 2,827 | ||||||||||||||
Actual return on plan assets | 285 | 387 | ||||||||||||||
Employer contributions | 162 | 12 | ||||||||||||||
Benefits paid | (149 | ) | (141 | ) | ||||||||||||
Fair value of plan assets at end of year | 3,383 | 3,085 | ||||||||||||||
Accrued liability | $ | (398 | ) | $ | (31 | ) | ||||||||||
At December 31, 2014, the projected benefit obligations for the qualified and non-qualified pension plans were $3.6 billion and $165 million, respectively. All pension plan assets are related to the qualified pension plan. | ||||||||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 118 | ||||||||||||
Other regulatory assets, deferred | 1,102 | 610 | ||||||||||||||
Current liabilities, other | (12 | ) | (12 | ) | ||||||||||||
Employee benefit obligations | (386 | ) | (137 | ) | ||||||||||||
Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | 17 | $ | 26 | $ | 9 | ||||||||||
Net (gain) loss | 1,085 | 584 | 76 | |||||||||||||
Regulatory assets | $ | 1,102 | $ | 610 | ||||||||||||
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 610 | $ | 1,132 | ||||||||||||
Net (gain) loss | 543 | (438 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (10 | ) | (10 | ) | ||||||||||||
Amortization of net gain (loss) | (41 | ) | (74 | ) | ||||||||||||
Total reclassification adjustments | (51 | ) | (84 | ) | ||||||||||||
Total change | 492 | (522 | ) | |||||||||||||
Ending balance | $ | 1,102 | $ | 610 | ||||||||||||
Components of net periodic pension cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 62 | $ | 69 | $ | 60 | ||||||||||
Interest cost | 153 | 138 | 141 | |||||||||||||
Expected return on plan assets | (228 | ) | (212 | ) | (221 | ) | ||||||||||
Recognized net loss | 41 | 74 | 33 | |||||||||||||
Net amortization | 10 | 10 | 12 | |||||||||||||
Net periodic pension cost | $ | 38 | $ | 79 | $ | 25 | ||||||||||
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. | ||||||||||||||||
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2014, estimated benefit payments were as follows: | ||||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 199 | ||||||||||||||
2016 | 169 | |||||||||||||||
2017 | 177 | |||||||||||||||
2018 | 183 | |||||||||||||||
2019 | 190 | |||||||||||||||
2020 to 2024 | 1,042 | |||||||||||||||
Other Postretirement Benefits | ||||||||||||||||
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 723 | $ | 800 | ||||||||||||
Service cost | 6 | 7 | ||||||||||||||
Interest cost | 34 | 31 | ||||||||||||||
Benefits paid | (44 | ) | (45 | ) | ||||||||||||
Actuarial (gain) loss | 142 | (73 | ) | |||||||||||||
Retiree drug subsidy | 3 | 3 | ||||||||||||||
Balance at end of year | 864 | 723 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 407 | 382 | ||||||||||||||
Actual return on plan assets | 21 | 56 | ||||||||||||||
Employer contributions | 8 | 11 | ||||||||||||||
Benefits paid | (41 | ) | (42 | ) | ||||||||||||
Fair value of plan assets at end of year | 395 | 407 | ||||||||||||||
Accrued liability | $ | (469 | ) | $ | (316 | ) | ||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Other regulatory assets, deferred | $ | 213 | $ | 69 | ||||||||||||
Employee benefit obligations | (469 | ) | (316 | ) | ||||||||||||
Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | (5 | ) | $ | (4 | ) | $ | — | ||||||||
Net (gain) loss | 218 | 73 | 11 | |||||||||||||
Regulatory assets | $ | 213 | $ | 69 | ||||||||||||
The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 69 | $ | 187 | ||||||||||||
Net (gain) loss | 146 | (106 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of transition obligation | — | (4 | ) | |||||||||||||
Amortization of net gain (loss) | (2 | ) | (8 | ) | ||||||||||||
Total reclassification adjustments | (2 | ) | (12 | ) | ||||||||||||
Total change | 144 | (118 | ) | |||||||||||||
Ending balance | $ | 213 | $ | 69 | ||||||||||||
Components of the other postretirement benefit plans' net periodic cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 6 | $ | 7 | $ | 7 | ||||||||||
Interest cost | 34 | 31 | 37 | |||||||||||||
Expected return on plan assets | (25 | ) | (24 | ) | (29 | ) | ||||||||||
Net amortization | 2 | 12 | 10 | |||||||||||||
Net periodic postretirement benefit cost | $ | 17 | $ | 26 | $ | 25 | ||||||||||
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | ||||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 53 | $ | (4 | ) | $ | 49 | |||||||||
2016 | 56 | (5 | ) | 51 | ||||||||||||
2017 | 57 | (5 | ) | 52 | ||||||||||||
2018 | 59 | (6 | ) | 53 | ||||||||||||
2019 | 59 | (6 | ) | 53 | ||||||||||||
2020 to 2024 | 289 | (32 | ) | 257 | ||||||||||||
Benefit Plan Assets | ||||||||||||||||
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. | ||||||||||||||||
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | ||||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 40 | % | 38 | % | 36 | % | ||||||||||
International equity | 21 | 26 | 30 | |||||||||||||
Domestic fixed income | 24 | 24 | 21 | |||||||||||||
Global fixed income | 8 | 7 | 8 | |||||||||||||
Special situations | 1 | — | — | |||||||||||||
Real estate investments | 4 | 4 | 3 | |||||||||||||
Private equity | 2 | 1 | 2 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. | ||||||||||||||||
Investment Strategies | ||||||||||||||||
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: | ||||||||||||||||
• | Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. | |||||||||||||||
• | International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | |||||||||||||||
• | Fixed income. A mix of domestic and international bonds. | |||||||||||||||
• | Trust-owned life insurance (TOLI). Investments of the Company's taxable trusts aimed at minimizing the impact of taxes on the portfolio. | |||||||||||||||
• | Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. | |||||||||||||||
• | Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. | |||||||||||||||
• | Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | |||||||||||||||
Benefit Plan Asset Fair Values | ||||||||||||||||
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2014 and 2013. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. | ||||||||||||||||
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: | ||||||||||||||||
• | Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. | |||||||||||||||
• | Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. | |||||||||||||||
• | TOLI. Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate account. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. | |||||||||||||||
• | Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. | |||||||||||||||
The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 595 | $ | 246 | $ | — | $ | 841 | ||||||||
International equity* | 373 | 344 | — | 717 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 244 | — | 244 | ||||||||||||
Mortgage- and asset-backed securities | — | 66 | — | 66 | ||||||||||||
Corporate bonds | — | 398 | — | 398 | ||||||||||||
Pooled funds | — | 179 | — | 179 | ||||||||||||
Cash equivalents and other | 1 | 230 | — | 231 | ||||||||||||
Real estate investments | 102 | — | 391 | 493 | ||||||||||||
Private equity | — | — | 199 | 199 | ||||||||||||
Total | $ | 1,071 | $ | 1,707 | $ | 590 | $ | 3,368 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (1 | ) | $ | — | $ | — | $ | (1 | ) | ||||||
Total | $ | 1,070 | $ | 1,707 | $ | 590 | $ | 3,367 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 506 | $ | 296 | $ | — | $ | 802 | ||||||||
International equity* | 389 | 359 | — | 748 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 212 | — | 212 | ||||||||||||
Mortgage- and asset-backed securities | — | 55 | — | 55 | ||||||||||||
Corporate bonds | — | 346 | — | 346 | ||||||||||||
Pooled funds | — | 166 | — | 166 | ||||||||||||
Cash equivalents and other | — | 79 | — | 79 | ||||||||||||
Real estate investments | 92 | — | 353 | 445 | ||||||||||||
Private equity | — | — | 202 | 202 | ||||||||||||
Total | $ | 987 | $ | 1,513 | $ | 555 | $ | 3,055 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | ||||||
Total | $ | 987 | $ | 1,512 | $ | 555 | $ | 3,054 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 353 | $ | 202 | $ | 299 | $ | 211 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 23 | 15 | 25 | 3 | ||||||||||||
Related to investments sold during the year | 12 | (6 | ) | 10 | 17 | |||||||||||
Total return on investments | 35 | 9 | 35 | 20 | ||||||||||||
Purchases, sales, and settlements | 3 | (12 | ) | 19 | (29 | ) | ||||||||||
Ending balance | $ | 391 | $ | 199 | $ | 353 | $ | 202 | ||||||||
The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 53 | $ | 40 | $ | — | $ | 93 | ||||||||
International equity* | 11 | 45 | — | 56 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 7 | — | 7 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 12 | — | 12 | ||||||||||||
Pooled funds | — | 29 | — | 29 | ||||||||||||
Cash equivalents and other | 8 | 11 | — | 19 | ||||||||||||
Trust-owned life insurance | — | 162 | — | 162 | ||||||||||||
Real estate investments | 3 | — | 12 | 15 | ||||||||||||
Private equity | — | — | 6 | 6 | ||||||||||||
Total | $ | 75 | $ | 308 | $ | 18 | $ | 401 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 74 | $ | 25 | $ | — | $ | 99 | ||||||||
International equity* | 12 | 57 | — | 69 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 7 | — | 7 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 11 | — | 11 | ||||||||||||
Pooled funds | — | 34 | — | 34 | ||||||||||||
Cash equivalents and other | — | 6 | — | 6 | ||||||||||||
Trust-owned life insurance | — | 158 | — | 158 | ||||||||||||
Real estate investments | 3 | — | 11 | 14 | ||||||||||||
Private equity | — | — | 6 | 6 | ||||||||||||
Total | $ | 89 | $ | 300 | $ | 17 | $ | 406 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 11 | $ | 6 | $ | 10 | $ | 7 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 1 | — | 1 | — | ||||||||||||
Related to investments sold during the year | — | — | — | — | ||||||||||||
Total return on investments | 1 | — | 1 | — | ||||||||||||
Purchases, sales, and settlements | — | — | — | (1 | ) | |||||||||||
Ending balance | $ | 12 | $ | 6 | $ | 11 | $ | 6 | ||||||||
Employee Savings Plan | ||||||||||||||||
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2014, 2013, and 2012 were $25 million, $24 million, and $24 million, respectively. | ||||||||||||||||
Gulf Power [Member] | ||||||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||||||
RETIREMENT BENEFITS | RETIREMENT BENEFITS | |||||||||||||||
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2014, the Company voluntarily contributed $30 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2015, no other postretirement trust contributions are expected. | ||||||||||||||||
Actuarial Assumptions | ||||||||||||||||
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%. | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.18 | % | 5.02 | % | 4.27 | % | ||||||||||
Other postretirement benefit plans | 4.04 | 4.86 | 4.06 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 8.08 | 8.04 | 8.02 | |||||||||||||
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. | ||||||||||||||||
For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $29.6 million and $2.6 million, respectively. | ||||||||||||||||
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | ||||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | ||||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in thousands) | ||||||||||||||||
Benefit obligation | $ | 3,934 | $ | (3,334 | ) | |||||||||||
Service and interest costs | 157 | (133 | ) | |||||||||||||
Pension Plans | ||||||||||||||||
The total accumulated benefit obligation for the pension plans was $438 million at December 31, 2014 and $353 million at December 31, 2013. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 395,328 | $ | 413,501 | ||||||||||||
Service cost | 10,181 | 11,128 | ||||||||||||||
Interest cost | 19,433 | 17,321 | ||||||||||||||
Benefits paid | (15,635 | ) | (14,831 | ) | ||||||||||||
Actuarial (gain) loss | 81,254 | (31,791 | ) | |||||||||||||
Balance at end of year | 490,561 | 395,328 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 385,639 | 350,260 | ||||||||||||||
Actual return on plan assets | 33,512 | 49,076 | ||||||||||||||
Employer contributions | 31,251 | 1,134 | ||||||||||||||
Benefits paid | (15,635 | ) | (14,831 | ) | ||||||||||||
Fair value of plan assets at end of year | 434,767 | 385,639 | ||||||||||||||
Accrued liability | $ | (55,794 | ) | $ | (9,689 | ) | ||||||||||
At December 31, 2014, the projected benefit obligations for the qualified and non-qualified pension plans were $464 million and $26 million, respectively. All pension plan assets are related to the qualified pension plan. | ||||||||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 11,533 | ||||||||||||
Other regulatory assets, deferred | 145,815 | 75,280 | ||||||||||||||
Current liabilities, other | (1,307 | ) | (1,183 | ) | ||||||||||||
Employee benefit obligations | (54,487 | ) | (20,039 | ) | ||||||||||||
Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | 3,286 | $ | 4,401 | $ | 1,115 | ||||||||||
Net (gain) loss | 142,529 | 70,879 | 9,281 | |||||||||||||
Regulatory assets | $ | 145,815 | $ | 75,280 | ||||||||||||
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 75,280 | $ | 139,261 | ||||||||||||
Net (gain) loss | 76,209 | (54,432 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1,115 | ) | (1,164 | ) | ||||||||||||
Amortization of net gain (loss) | (4,559 | ) | (8,385 | ) | ||||||||||||
Total reclassification adjustments | (5,674 | ) | (9,549 | ) | ||||||||||||
Total change | 70,535 | (63,981 | ) | |||||||||||||
Ending balance | $ | 145,815 | $ | 75,280 | ||||||||||||
Components of net periodic pension cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 10,181 | $ | 11,128 | $ | 9,101 | ||||||||||
Interest cost | 19,433 | 17,321 | 17,199 | |||||||||||||
Expected return on plan assets | (28,468 | ) | (26,435 | ) | (25,932 | ) | ||||||||||
Recognized net (gain) loss | 4,559 | 8,385 | 3,913 | |||||||||||||
Net amortization | 1,115 | 1,164 | 1,262 | |||||||||||||
Net periodic pension cost | $ | 6,820 | $ | 11,563 | $ | 5,543 | ||||||||||
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. | ||||||||||||||||
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2014, estimated benefit payments were as follows: | ||||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 22,002 | ||||||||||||||
2016 | 18,683 | |||||||||||||||
2017 | 19,950 | |||||||||||||||
2018 | 21,019 | |||||||||||||||
2019 | 22,229 | |||||||||||||||
2020 to 2024 | 129,877 | |||||||||||||||
Other Postretirement Benefits | ||||||||||||||||
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 68,579 | $ | 75,395 | ||||||||||||
Service cost | 1,163 | 1,355 | ||||||||||||||
Interest cost | 3,235 | 2,982 | ||||||||||||||
Benefits paid | (4,061 | ) | (3,583 | ) | ||||||||||||
Actuarial (gain) loss | 11,317 | (7,900 | ) | |||||||||||||
Plan amendment | (2,089 | ) | — | |||||||||||||
Retiree drug subsidy | 357 | 330 | ||||||||||||||
Balance at end of year | 78,501 | 68,579 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 17,474 | 16,227 | ||||||||||||||
Actual return on plan assets | 1,578 | 2,119 | ||||||||||||||
Employer contributions | 2,846 | 2,381 | ||||||||||||||
Benefits paid | (3,704 | ) | (3,253 | ) | ||||||||||||
Fair value of plan assets at end of year | 18,194 | 17,474 | ||||||||||||||
Accrued liability | $ | (60,307 | ) | $ | (51,105 | ) | ||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Other regulatory assets, deferred | $ | 6,100 | $ | — | ||||||||||||
Current liabilities, other | (639 | ) | (687 | ) | ||||||||||||
Other regulatory liabilities, deferred | (4,290 | ) | (6,984 | ) | ||||||||||||
Employee benefit obligations | (59,668 | ) | (50,418 | ) | ||||||||||||
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | (2,137 | ) | $ | 138 | $ | 25 | |||||||||
Net (gain) loss | 3,947 | (7,122 | ) | — | ||||||||||||
Net regulatory assets (liabilities) | $ | 1,810 | $ | (6,984 | ) | |||||||||||
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Net regulatory assets (liabilities): | ||||||||||||||||
Beginning balance | $ | (6,984 | ) | $ | 2,169 | |||||||||||
Net (gain) loss | 11,045 | (8,967 | ) | |||||||||||||
Change in prior service costs | (2,089 | ) | — | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (186 | ) | (186 | ) | ||||||||||||
Amortization of net gain (loss) | 24 | — | ||||||||||||||
Total reclassification adjustments | (162 | ) | (186 | ) | ||||||||||||
Total change | 8,794 | (9,153 | ) | |||||||||||||
Ending balance | $ | 1,810 | $ | (6,984 | ) | |||||||||||
Components of the other postretirement benefit plans' net periodic cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 1,163 | $ | 1,355 | $ | 1,167 | ||||||||||
Interest cost | 3,235 | 2,982 | 3,367 | |||||||||||||
Expected return on plan assets | (1,306 | ) | (1,238 | ) | (1,311 | ) | ||||||||||
Net amortization | 162 | 186 | 379 | |||||||||||||
Net periodic postretirement benefit cost | $ | 3,254 | $ | 3,285 | $ | 3,602 | ||||||||||
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | ||||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 4,694 | $ | (431 | ) | $ | 4,263 | |||||||||
2016 | 4,982 | (480 | ) | 4,502 | ||||||||||||
2017 | 5,136 | (535 | ) | 4,601 | ||||||||||||
2018 | 5,300 | (594 | ) | 4,706 | ||||||||||||
2019 | 5,326 | (660 | ) | 4,666 | ||||||||||||
2020 to 2024 | 27,399 | (3,430 | ) | 23,969 | ||||||||||||
Benefit Plan Assets | ||||||||||||||||
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. | ||||||||||||||||
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | ||||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 25 | % | 29 | % | 30 | % | ||||||||||
International equity | 24 | 22 | 24 | |||||||||||||
Domestic fixed income | 25 | 29 | 25 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. | ||||||||||||||||
Investment Strategies | ||||||||||||||||
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: | ||||||||||||||||
• | Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. | |||||||||||||||
• | International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | |||||||||||||||
• | Fixed income. A mix of domestic and international bonds. | |||||||||||||||
• | Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. | |||||||||||||||
• | Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. | |||||||||||||||
• | Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | |||||||||||||||
Benefit Plan Asset Fair Values | ||||||||||||||||
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2014 and 2013. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. | ||||||||||||||||
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: | ||||||||||||||||
• | Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. | |||||||||||||||
• | Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. | |||||||||||||||
• | Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. | |||||||||||||||
The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 76,460 | $ | 31,588 | $ | — | $ | 108,048 | ||||||||
International equity* | 47,988 | 44,223 | — | 92,211 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 31,372 | — | 31,372 | ||||||||||||
Mortgage- and asset-backed securities | — | 8,438 | — | 8,438 | ||||||||||||
Corporate bonds | — | 50,931 | — | 50,931 | ||||||||||||
Pooled funds | — | 23,063 | — | 23,063 | ||||||||||||
Cash equivalents and other | 130 | 29,597 | — | 29,727 | ||||||||||||
Real estate investments | 13,154 | — | 50,281 | 63,435 | ||||||||||||
Private equity | — | — | 25,573 | 25,573 | ||||||||||||
Total | $ | 137,732 | $ | 219,212 | $ | 75,854 | $ | 432,798 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (87 | ) | $ | — | $ | — | $ | (87 | ) | ||||||
Total | $ | 137,645 | $ | 219,212 | $ | 75,854 | $ | 432,711 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 63,269 | $ | 37,037 | $ | — | $ | 100,306 | ||||||||
International equity* | 48,606 | 44,941 | — | 93,547 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 26,461 | — | 26,461 | ||||||||||||
Mortgage- and asset-backed securities | — | 6,873 | — | 6,873 | ||||||||||||
Corporate bonds | — | 43,222 | — | 43,222 | ||||||||||||
Pooled funds | — | 20,810 | — | 20,810 | ||||||||||||
Cash equivalents and other | 38 | 9,851 | — | 9,889 | ||||||||||||
Real estate investments | 11,493 | — | 44,139 | 55,632 | ||||||||||||
Private equity | — | — | 25,201 | 25,201 | ||||||||||||
Total | $ | 123,406 | $ | 189,195 | $ | 69,340 | $ | 381,941 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (115 | ) | $ | — | $ | (115 | ) | ||||||
Total | $ | 123,406 | $ | 189,080 | $ | 69,340 | $ | 381,826 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 44,139 | $ | 25,201 | $ | 37,039 | $ | 26,129 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 4,263 | 2,697 | 3,357 | 376 | ||||||||||||
Related to investments sold during the year | 1,488 | (727 | ) | 1,310 | 2,282 | |||||||||||
Total return on investments | 5,751 | 1,970 | 4,667 | 2,658 | ||||||||||||
Purchases, sales, and settlements | 391 | (1,598 | ) | 2,433 | (3,586 | ) | ||||||||||
Ending balance | $ | 50,281 | $ | 25,573 | $ | 44,139 | $ | 25,201 | ||||||||
The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 3,105 | $ | 1,283 | $ | — | $ | 4,388 | ||||||||
International equity* | 1,949 | 1,798 | — | 3,747 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 1,274 | — | 1,274 | ||||||||||||
Mortgage- and asset-backed securities | — | 342 | — | 342 | ||||||||||||
Corporate bonds | — | 2,071 | — | 2,071 | ||||||||||||
Pooled funds | — | 937 | — | 937 | ||||||||||||
Cash equivalents and other | 510 | 1,203 | — | 1,713 | ||||||||||||
Real estate investments | 534 | — | 2,042 | 2,576 | ||||||||||||
Private equity | — | — | 1,039 | 1,039 | ||||||||||||
Total | $ | 6,098 | $ | 8,908 | $ | 3,081 | $ | 18,087 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (4 | ) | $ | — | $ | — | $ | (4 | ) | ||||||
Total | $ | 6,094 | $ | 8,908 | $ | 3,081 | $ | 18,083 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 2,778 | $ | 1,628 | $ | — | $ | 4,406 | ||||||||
International equity* | 2,136 | 1,973 | — | 4,109 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 1,161 | — | 1,161 | ||||||||||||
Mortgage- and asset-backed securities | — | 303 | — | 303 | ||||||||||||
Corporate bonds | — | 1,897 | — | 1,897 | ||||||||||||
Pooled funds | — | 1,417 | — | 1,417 | ||||||||||||
Cash equivalents and other | 1 | 433 | — | 434 | ||||||||||||
Real estate investments | 504 | — | 1,939 | 2,443 | ||||||||||||
Private equity | — | — | 1,108 | 1,108 | ||||||||||||
Total | $ | 5,419 | $ | 8,812 | $ | 3,047 | $ | 17,278 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (5 | ) | $ | — | $ | (5 | ) | ||||||
Total | $ | 5,419 | $ | 8,807 | $ | 3,047 | $ | 17,273 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate | Private | Real Estate | Private | |||||||||||||
Investments | Equity | Investments | Equity | |||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 1,939 | $ | 1,108 | $ | 1,667 | $ | 1,155 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 27 | 26 | 108 | 16 | ||||||||||||
Related to investments sold during the year | 60 | (30 | ) | 57 | 104 | |||||||||||
Total return on investments | 87 | (4 | ) | 165 | 120 | |||||||||||
Purchases, sales, and settlements | 16 | (65 | ) | 107 | (167 | ) | ||||||||||
Ending balance | $ | 2,042 | $ | 1,039 | $ | 1,939 | $ | 1,108 | ||||||||
Employee Savings Plan | ||||||||||||||||
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2014, 2013, and 2012 were $4.2 million, $4.1 million, and $4.0 million, respectively. | ||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||||||
RETIREMENT BENEFITS | RETIREMENT BENEFITS | |||||||||||||||
The Company has a defined benefit, trusteed, pension plan covering substantially all employees. This qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In December 2014, the Company voluntarily contributed $33 million to the qualified pension plan. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2015. The Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, the Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The Company funds its other postretirement trusts to the extent required by the FERC. For the year ending December 31, 2015, no other postretirement trust contributions are expected. | ||||||||||||||||
Actuarial Assumptions | ||||||||||||||||
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.87%, respectively, and an annual salary increase of 3.84%. | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.17 | % | 5.01 | % | 4.26 | % | ||||||||||
Other postretirement benefit plans | 4.03 | 4.85 | 4.04 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 7.3 | 7.04 | 6.96 | |||||||||||||
The Company estimates the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of seven different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. | ||||||||||||||||
For purposes of its December 31, 2014 measurement date, the Company adopted new mortality tables for its pension plans and retiree life and medical plans, which reflect increased life expectancies in the U.S. The adoption of new mortality tables increased the projected benefit obligations for the Company's pension plans and other postretirement benefit plans by approximately $30.2 million and $5.2 million, respectively. | ||||||||||||||||
An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | ||||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | ||||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in thousands) | ||||||||||||||||
Benefit obligation | $ | 6,241 | $ | (5,289 | ) | |||||||||||
Service and interest costs | 250 | (212 | ) | |||||||||||||
Pension Plans | ||||||||||||||||
The total accumulated benefit obligation for the pension plans was $462 million at December 31, 2014 and $370 million at December 31, 2013. Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 409,395 | $ | 432,553 | ||||||||||||
Service cost | 10,123 | 11,067 | ||||||||||||||
Interest cost | 20,093 | 18,062 | ||||||||||||||
Benefits paid | (17,499 | ) | (16,207 | ) | ||||||||||||
Actuarial (gain) loss | 90,735 | (36,080 | ) | |||||||||||||
Balance at end of year | 512,847 | 409,395 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 387,403 | 351,749 | ||||||||||||||
Actual return on plan assets | 40,051 | 49,431 | ||||||||||||||
Employer contributions | 35,526 | 2,430 | ||||||||||||||
Benefits paid | (17,499 | ) | (16,207 | ) | ||||||||||||
Fair value of plan assets at end of year | 445,481 | 387,403 | ||||||||||||||
Accrued liability | $ | (67,366 | ) | $ | (21,992 | ) | ||||||||||
At December 31, 2014, the projected benefit obligations for the qualified and non-qualified pension plans were $481 million and $32 million, respectively. All pension plan assets are related to the qualified pension plan. | ||||||||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 5,698 | ||||||||||||
Other regulatory assets, deferred | 150,972 | 77,572 | ||||||||||||||
Other current liabilities | (2,337 | ) | (2,134 | ) | ||||||||||||
Employee benefit obligations | (65,029 | ) | (25,556 | ) | ||||||||||||
Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | 3,030 | $ | 4,118 | $ | 1,088 | ||||||||||
Net (gain) loss | 147,942 | 73,454 | 10,293 | |||||||||||||
Regulatory assets | $ | 150,972 | $ | 77,572 | ||||||||||||
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 77,572 | $ | 146,838 | ||||||||||||
Net (gain) loss | 79,425 | (58,662 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1,088 | ) | (1,143 | ) | ||||||||||||
Amortization of net gain (loss) | (4,937 | ) | (9,461 | ) | ||||||||||||
Total reclassification adjustments | (6,025 | ) | (10,604 | ) | ||||||||||||
Total change | 73,400 | (69,266 | ) | |||||||||||||
Ending balance | $ | 150,972 | $ | 77,572 | ||||||||||||
Components of net periodic pension cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 10,123 | $ | 11,067 | $ | 9,416 | ||||||||||
Interest cost | 20,093 | 18,062 | 18,019 | |||||||||||||
Expected return on plan assets | (28,742 | ) | (26,849 | ) | (24,121 | ) | ||||||||||
Recognized net (gain) loss | 4,937 | 9,461 | 4,100 | |||||||||||||
Net amortization | 1,088 | 1,143 | 1,309 | |||||||||||||
Net periodic pension cost | $ | 7,499 | $ | 12,884 | $ | 8,723 | ||||||||||
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Company has elected to amortize changes in the market value of all plan assets over five years rather than recognize the changes immediately. As a result, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets. | ||||||||||||||||
Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2014, estimated benefit payments were as follows: | ||||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 23,304 | ||||||||||||||
2016 | 19,551 | |||||||||||||||
2017 | 20,816 | |||||||||||||||
2018 | 21,905 | |||||||||||||||
2019 | 23,337 | |||||||||||||||
2020 to 2024 | 135,320 | |||||||||||||||
Other Postretirement Benefits | ||||||||||||||||
Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 80,940 | $ | 91,783 | ||||||||||||
Service cost | 1,025 | 1,151 | ||||||||||||||
Interest cost | 3,812 | 3,619 | ||||||||||||||
Benefits paid | (4,887 | ) | (4,080 | ) | ||||||||||||
Actuarial (gain) loss | 14,259 | (11,959 | ) | |||||||||||||
Retiree drug subsidy | 506 | 426 | ||||||||||||||
Balance at end of year | 95,655 | 80,940 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 23,277 | 21,990 | ||||||||||||||
Actual return on plan assets | 1,814 | 2,379 | ||||||||||||||
Employer contributions | 3,413 | 2,562 | ||||||||||||||
Benefits paid | (4,381 | ) | (3,654 | ) | ||||||||||||
Fair value of plan assets at end of year | 24,123 | 23,277 | ||||||||||||||
Accrued liability | $ | (71,532 | ) | $ | (57,663 | ) | ||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Other regulatory assets, deferred | $ | 18,345 | $ | 5,227 | ||||||||||||
Other regulatory liabilities, deferred | (2,011 | ) | (3,111 | ) | ||||||||||||
Employee benefit obligations | (71,532 | ) | (57,663 | ) | ||||||||||||
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | (2,123 | ) | $ | (2,311 | ) | $ | (188 | ) | |||||||
Net (gain) loss | 18,457 | 4,427 | 778 | |||||||||||||
Net regulatory assets | $ | 16,334 | $ | 2,116 | ||||||||||||
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Net regulatory assets (liabilities): | ||||||||||||||||
Beginning balance | $ | 2,116 | $ | 15,454 | ||||||||||||
Net (gain) loss | 14,030 | (12,867 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | 188 | 188 | ||||||||||||||
Amortization of net gain (loss) | — | (659 | ) | |||||||||||||
Total reclassification adjustments | 188 | (471 | ) | |||||||||||||
Total change | 14,218 | (13,338 | ) | |||||||||||||
Ending balance | $ | 16,334 | $ | 2,116 | ||||||||||||
Components of the other postretirement benefit plans' net periodic cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 1,025 | $ | 1,151 | $ | 1,038 | ||||||||||
Interest cost | 3,812 | 3,619 | 4,155 | |||||||||||||
Expected return on plan assets | (1,585 | ) | (1,472 | ) | (1,552 | ) | ||||||||||
Net amortization | (188 | ) | 471 | 470 | ||||||||||||
Net periodic postretirement benefit cost | $ | 3,064 | $ | 3,769 | $ | 4,111 | ||||||||||
Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | ||||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 5,387 | $ | (512 | ) | $ | 4,875 | |||||||||
2016 | 5,632 | (566 | ) | 5,066 | ||||||||||||
2017 | 5,911 | (622 | ) | 5,289 | ||||||||||||
2018 | 6,185 | (680 | ) | 5,505 | ||||||||||||
2019 | 6,475 | (735 | ) | 5,740 | ||||||||||||
2020 to 2024 | 34,139 | (3,744 | ) | 30,395 | ||||||||||||
Benefit Plan Assets | ||||||||||||||||
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended (Internal Revenue Code). The Company's investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Derivative instruments are used primarily to gain efficient exposure to the various asset classes and as hedging tools. The Company minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk. | ||||||||||||||||
The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | ||||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 21 | % | 24 | % | 25 | % | ||||||||||
International equity | 21 | 19 | 20 | |||||||||||||
Domestic fixed income | 37 | 41 | 38 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 11 | 11 | 11 | |||||||||||||
Private equity | 7 | 4 | 5 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
The investment strategy for plan assets related to the Company's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Company employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. | ||||||||||||||||
Investment Strategies | ||||||||||||||||
Detailed below is a description of the investment strategies for each major asset category for the pension and other postretirement benefit plans disclosed above: | ||||||||||||||||
• | Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. | |||||||||||||||
• | International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches. | |||||||||||||||
• | Fixed income. A mix of domestic and international bonds. | |||||||||||||||
• | Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature. | |||||||||||||||
• | Real estate investments. Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. | |||||||||||||||
• | Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | |||||||||||||||
Benefit Plan Asset Fair Values | ||||||||||||||||
Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2014 and 2013. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. | ||||||||||||||||
Valuation methods of the primary fair value measurements disclosed in the following tables are as follows: | ||||||||||||||||
• | Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities. | |||||||||||||||
• | Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. | |||||||||||||||
• | Real estate investments and private equity. Investments in private equity and real estate are generally classified as Level 3 as the underlying assets typically do not have observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. In the case of private equity, techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, and discounted cash flow analysis. Real estate managers generally use prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals to value underlying real estate investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. | |||||||||||||||
The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 78,344 | $ | 32,366 | $ | — | $ | 110,710 | ||||||||
International equity* | 49,170 | 45,313 | — | 94,483 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 32,145 | — | 32,145 | ||||||||||||
Mortgage- and asset-backed securities | — | 8,646 | — | 8,646 | ||||||||||||
Corporate bonds | — | 52,185 | — | 52,185 | ||||||||||||
Pooled funds | — | 23,632 | — | 23,632 | ||||||||||||
Cash equivalents and other | 133 | 30,327 | — | 30,460 | ||||||||||||
Real estate investments | 13,479 | — | 51,520 | 64,999 | ||||||||||||
Private equity | — | — | 26,203 | 26,203 | ||||||||||||
Total | $ | 141,126 | $ | 224,614 | $ | 77,723 | $ | 443,463 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (89 | ) | $ | — | $ | — | $ | (89 | ) | ||||||
Total | $ | 141,037 | $ | 224,614 | $ | 77,723 | $ | 443,374 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 63,558 | $ | 37,206 | $ | — | $ | 100,764 | ||||||||
International equity* | 48,829 | 45,146 | — | 93,975 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 26,582 | — | 26,582 | ||||||||||||
Mortgage- and asset-backed securities | — | 6,904 | — | 6,904 | ||||||||||||
Corporate bonds | — | 43,420 | — | 43,420 | ||||||||||||
Pooled funds | — | 20,905 | — | 20,905 | ||||||||||||
Cash equivalents and other | 38 | 9,896 | — | 9,934 | ||||||||||||
Real estate investments | 11,546 | — | 44,341 | 55,887 | ||||||||||||
Private equity | — | — | 25,316 | 25,316 | ||||||||||||
Total | $ | 123,971 | $ | 190,059 | $ | 69,657 | $ | 383,687 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (115 | ) | $ | — | $ | (115 | ) | ||||||
Total | $ | 123,971 | $ | 189,944 | $ | 69,657 | $ | 383,572 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate | Private Equity | Real Estate | Private Equity | |||||||||||||
Investments | Investments | |||||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 44,341 | $ | 25,316 | $ | 37,196 | $ | 26,240 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 5,253 | 3,269 | 3,385 | 378 | ||||||||||||
Related to investments sold during the year | 1,525 | (745 | ) | 1,316 | 2,300 | |||||||||||
Total return on investments | 6,778 | 2,524 | 4,701 | 2,678 | ||||||||||||
Purchases, sales, and settlements | 401 | (1,637 | ) | 2,444 | (3,602 | ) | ||||||||||
Ending balance | $ | 51,520 | $ | 26,203 | $ | 44,341 | $ | 25,316 | ||||||||
The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 3,450 | $ | 1,425 | $ | — | $ | 4,875 | ||||||||
International equity* | 2,165 | 1,997 | — | 4,162 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 5,279 | — | 5,279 | ||||||||||||
Mortgage- and asset-backed securities | — | 380 | — | 380 | ||||||||||||
Corporate bonds | — | 2,301 | — | 2,301 | ||||||||||||
Pooled funds | — | 1,041 | — | 1,041 | ||||||||||||
Cash equivalents and other | 589 | 1,337 | — | 1,926 | ||||||||||||
Real estate investments | 593 | — | 2,269 | 2,862 | ||||||||||||
Private equity | — | — | 1,154 | 1,154 | ||||||||||||
Total | $ | 6,797 | $ | 13,760 | $ | 3,423 | $ | 23,980 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (5 | ) | $ | — | $ | — | $ | (5 | ) | ||||||
Total | $ | 6,792 | $ | 13,760 | $ | 3,423 | $ | 23,975 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 3,089 | $ | 1,809 | $ | — | $ | 4,898 | ||||||||
International equity* | 2,375 | 2,193 | — | 4,568 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 5,213 | — | 5,213 | ||||||||||||
Mortgage- and asset-backed securities | — | 337 | — | 337 | ||||||||||||
Corporate bonds | — | 2,109 | — | 2,109 | ||||||||||||
Pooled funds | — | 1,016 | — | 1,016 | ||||||||||||
Cash equivalents and other | 1 | 968 | — | 969 | ||||||||||||
Real estate investments | 560 | — | 2,156 | 2,716 | ||||||||||||
Private equity | — | — | 1,231 | 1,231 | ||||||||||||
Total | $ | 6,025 | $ | 13,645 | $ | 3,387 | $ | 23,057 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (5 | ) | $ | — | $ | (5 | ) | ||||||
Total | $ | 6,025 | $ | 13,640 | $ | 3,387 | $ | 23,052 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 2,156 | $ | 1,231 | $ | 1,865 | $ | 1,293 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 28 | 28 | 158 | 18 | ||||||||||||
Related to investments sold during the year | 67 | (33 | ) | 64 | 110 | |||||||||||
Total return on investments | 95 | (5 | ) | 222 | 128 | |||||||||||
Purchases, sales, and settlements | 18 | (72 | ) | 69 | (190 | ) | ||||||||||
Ending balance | $ | 2,269 | $ | 1,154 | $ | 2,156 | $ | 1,231 | ||||||||
Employee Savings Plan | ||||||||||||||||
The Company also sponsors a 401(k) defined contribution plan covering substantially all employees. The Company provides an 85% matching contribution on up to 6% of an employee's base salary. Total matching contributions made to the plan for 2014, 2013, and 2012 were $4.6 million, $4.1 million, and $3.9 million, respectively. |
Acquisitions
Acquisitions (Southern Power [Member]) | 12 Months Ended |
Dec. 31, 2014 | |
Southern Power [Member] | |
Business Acquisition [Line Items] | |
ACQUISITIONS | ACQUISITIONS |
2014 | |
Adobe Solar, LLC | |
On April 17, 2014, the Company and TRE, through STR, a jointly-owned subsidiary owned 90% by the Company, acquired all of the outstanding membership interests of Adobe from Sun Edison, LLC, the original developer of the project. Adobe constructed and owns an approximately 20-MW solar generating facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and the entire output of the plant is contracted under a 20-year PPA with SCE. The acquisition was in accordance with the Company's overall growth strategy. | |
The Company's acquisition of Adobe included cash consideration of approximately $96.2 million, which included TRE's 10% equity contribution. The fair values of the assets, liabilities, and intangibles acquired were recorded as follows: $83.5 million to property, plant, and equipment, $14.5 million to prepayment related to transmission services, and $6.3 million to PPA intangible, resulting in a $5.2 million bargain purchase gain with a $2.9 million deferred tax liability. The bargain purchase gain is included in other income (expense), net in the Company's Statements of Income herein. Acquisition-related costs were expensed as incurred and were not material. | |
Macho Springs Solar, LLC | |
On May 22, 2014, the Company and TRE, through STR, acquired all of the outstanding membership interests of Macho Springs from First Solar Development, LLC, the original developer of the project. Macho Springs constructed and owns an approximately 50-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23, 2014 and the entire output of the plant is contracted under a 20-year PPA with EPE. The acquisition was in accordance with the Company's overall growth strategy. | |
The Company's acquisition of Macho Springs included cash consideration of approximately $130.0 million, which included TRE's 10% equity contribution. The fair values of the assets acquired were recorded as follows: $128.0 million to property, plant, and equipment, $1.0 million to prepaid property taxes, and $1.0 million to prepayment related to transmission services. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material. | |
SG2 Imperial Valley, LLC | |
On October 22, 2014, the Company, through its subsidiaries SRP and SG2 Holdings, acquired all of the outstanding membership interests of Imperial Valley from a wholly-owned subsidiary of First Solar, the developer of the project. Imperial Valley constructed and owns an approximately 150-MW solar photovoltaic facility in Southern California. The solar facility began commercial operation on November 26, 2014 and at that time a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The entire output of the plant is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy (SDG&E). The acquisition was in accordance with the Company's overall growth strategy. | |
In connection with this acquisition, SG2 Holdings made an aggregate payment of approximately $127.9 million to a subsidiary of First Solar and became obligated to pay additional contingent consideration of approximately $599.3 million upon completion of the facility (representing the amount due to an affiliate of First Solar under the construction contract for Imperial Valley). When substantial completion was achieved on November 26, 2014, a subsidiary of First Solar was admitted as a minority member of SG2 Holdings. The members of SG2 Holdings made additional agreed upon capital contributions totaling $593.3 million to SG2 Holdings that were used to pay the contingent consideration due, leaving $6.0 million of contingent consideration payable upon final acceptance of the facility. As a result of these capital contributions, the aggregate purchase price payable by the Company for the acquisition of Imperial Valley was approximately $504.7 million in addition to the $222.5 million noncash contribution by the minority member. Following these capital contributions, the Company indirectly owns 100% of the class A membership interests of SG2 Holdings and is entitled to 51% of all cash distributions from SG2 Holdings, and First Solar indirectly owns 100% of the class B membership interests of SG2 Holdings and is entitled to 49% of all cash distributions from SG2 Holdings. In addition, the Company is entitled to substantially all of the federal tax benefits with respect to this transaction. As of December 31, 2014, the fair values of the assets acquired were recorded as follows: $707.5 million to property, plant, and equipment and $19.7 million to prepayment related to transmission services; however, the allocation of the purchase price to individual assets has not been finalized. Acquisition-related costs were expensed as incurred and were not material. | |
2013 | |
Campo Verde Solar, LLC | |
In April 2013, the Company and TRE, through STR, acquired all of the outstanding membership interests of Campo Verde from First Solar, the developer of the project. Campo Verde constructed and owns an approximately 139-MW solar photovoltaic facility in Southern California. The solar facility began commercial operation in October 2013 and the entire output of the plant is contracted under a 20-year PPA with SDG&E. The asset acquisition was in accordance with the Company's overall growth strategy. | |
The Company's acquisition of Campo Verde included cash consideration of $136.6 million, which included TRE's 10% equity contribution. The fair value of the assets acquired was allocated entirely to property, plant, and equipment. The acquisition did not include any contingent consideration and due diligence costs were expensed as incurred and were not material. Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar for construction of the solar facility. | |
Subsequent Events | |
Decatur County Solar Projects | |
On February 19, 2015, the Company acquired all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. as part of the Company's plans to build two solar photovoltaic facilities; the Decatur Parkway Solar Project and the Decatur County Solar Project. These two projects, approximately 80-MW and 19-MW, respectively, will be constructed on separate sites in Decatur County, Georgia. The construction of the Decatur Parkway Solar Project commenced in February 2015 while the construction of the Decatur County Solar Project is expected to commence in June 2015. Both projects are expected to begin commercial operation in late 2015, and the entire output of each project is contracted to Georgia Power. The entire output of the Decatur Parkway Solar Project is contracted under a 25-year PPA with Georgia Power and the entire output of the Decatur County Solar Project is contracted under a separate 20-year PPA with Georgia Power. The total estimated cost of the facilities is expected to be between $200 million and $220 million, which includes the acquisition price for all of the outstanding membership interests of Decatur Parkway Solar Project, LLC and Decatur County Solar Project, LLC from TradeWind Energy, Inc. The acquisition is in accordance with the Company's overall growth strategy. | |
Kay County Wind Facility | |
On February 24, 2015, the Company, through its wholly-owned subsidiary SRE, entered into a purchase agreement with Kay Wind Holdings, LLC, a wholly-owned subsidiary of Apex Clean Energy Holdings, LLC, the developer of the project, to acquire all of the outstanding membership interests of Kay Wind. Kay Wind is constructing an approximately 299-MW wind facility in Kay County, Oklahoma. The wind facility is expected to begin commercial operation in late 2015. The entire output of the facility is contracted under separate 20-year PPAs with Westar Energy, Inc. and Grand River Dam Authority. The acquisition is in accordance with the Company's overall growth strategy. | |
The Company's acquisition of Kay Wind is expected to close in the fourth quarter 2015 and the purchase price is expected to be approximately $492 million, with potential purchase price adjustments based on performance testing. The completion of the acquisition is subject to Kay Wind achieving certain financing, construction, and project milestones, and various customary conditions to closing. The ultimate outcome of this matter cannot be determined at this time. |
Contingencies_and_Regulatory_M
Contingencies and Regulatory Matters | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS | |||||||||||
General Litigation Matters | ||||||||||||
Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against Southern Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. | ||||||||||||
Insurance Recovery | ||||||||||||
Mirant Corporation (Mirant) was an energy company with businesses that included independent power projects and energy trading and risk management companies in the U.S. and other countries. Mirant was a wholly-owned subsidiary of Southern Company until its initial public offering in 2000. In 2001, Southern Company completed a spin-off to its stockholders of its remaining ownership, and Mirant became an independent corporate entity. | ||||||||||||
In 2003, Mirant and certain of its affiliates filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. In 2005, Mirant, as a debtor in possession, and the unsecured creditors' committee filed a complaint against Southern Company. Later in 2005, this complaint was transferred to MC Asset Recovery, LLC (MC Asset Recovery) as part of Mirant's plan of reorganization. In 2009, Southern Company entered into a settlement agreement with MC Asset Recovery to resolve this action. The settlement included an agreement where Southern Company paid MC Asset Recovery $202 million. Southern Company filed an insurance claim in 2009 to recover a portion of this settlement and received payments from its insurance provider of $25 million in June 2012 and $15 million in December 2013. Additionally, legal fees related to these insurance settlements totaled approximately $6 million in 2012 and $4 million in 2013. As a result, the net reduction to expense presented as MC Asset Recovery insurance settlement in the statement of income was approximately $19 million in 2012 and $11 million in 2013. | ||||||||||||
Environmental Matters | ||||||||||||
New Source Review Actions | ||||||||||||
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power and Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including units co-owned by Gulf Power and Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against Georgia Power (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. The case against Alabama Power (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. In September 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings. | ||||||||||||
Southern Company believes the traditional operating companies complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Environmental Remediation | ||||||||||||
The Southern Company system must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up properties. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs. | ||||||||||||
Georgia Power's environmental remediation liability as of December 31, 2014 was $22 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated. | ||||||||||||
Georgia Power and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to Georgia Power and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, Georgia Power filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified Georgia Power in 2011 that it is considering enforcement options against Georgia Power and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO. | ||||||||||||
In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In February 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion, ruling that Georgia Power has no liability in the private action. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit. | ||||||||||||
The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's financial statements. | ||||||||||||
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $48 million as of December 31, 2014. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income. | ||||||||||||
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management does not believe that additional liabilities, if any, at these sites would be material to the financial statements. | ||||||||||||
Nuclear Fuel Disposal Costs | ||||||||||||
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plants Hatch and Farley and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract. | ||||||||||||
As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered approximately $17 million, representing the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 2012, Alabama Power credited the award to cost of service for the benefit of customers. Also in 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers. | ||||||||||||
On December 12, 2014, the Court of Federal Claims entered a judgment in favor of Georgia Power and Alabama Power in the second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. Georgia Power was awarded approximately $18 million, based on its ownership interests, and Alabama Power was awarded approximately $26 million. No amounts have been recognized in the financial statements as of December 31, 2014. The final outcome of this matter cannot be determined at this time; however, no material impact on Southern Company's net income is expected. | ||||||||||||
On March 4, 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2014 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's net income is expected. | ||||||||||||
On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant. | ||||||||||||
Retail Regulatory Matters | ||||||||||||
Alabama Power | ||||||||||||
Rate RSE | ||||||||||||
Alabama Power's Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If Alabama Power's actual retail return is above the allowed weighted cost of equity (WCE) range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. Prior to 2014, retail rates remained unchanged when the retail ROE was projected to be between 13.0% and 14.5%. | ||||||||||||
During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. In August 2013, the Alabama PSC voted to issue a report on Rate RSE that found that Alabama Power's Rate RSE mechanism continues to be just and reasonable to customers and Alabama Power, but recommended Alabama Power modify Rate RSE as follows: | ||||||||||||
• | Eliminate the provision of Rate RSE establishing an allowed range of ROE. | |||||||||||
• | Eliminate the provision of Rate RSE limiting Alabama Power's capital structure to an allowed equity ratio of 45%. | |||||||||||
• | Replace these two provisions with a provision that establishes rates based upon the WCE range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%. | |||||||||||
• | Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. | |||||||||||
Substantially all other provisions of Rate RSE were unchanged. | ||||||||||||
In August 2013, Alabama Power filed its consent to these recommendations with the Alabama PSC. The changes became effective for calendar year 2014. In November 2013, Alabama Power made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2014; projected earnings were within the specified WCE range and, therefore, retail rates under Rate RSE remained unchanged for 2014. In 2012 and 2013, retail rates under Rate RSE remained unchanged from 2011. Under the terms of Rate RSE, the maximum possible increase for 2015 is 5.00%. | ||||||||||||
On December 1, 2014, Alabama Power submitted the required annual filing under Rate RSE to the Alabama PSC. The Rate RSE increase was 3.49%, or $181 million annually, effective January 1, 2015. The revenue adjustment includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2016 cannot exceed 4.51%. | ||||||||||||
Rate CNP | ||||||||||||
Alabama Power's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. Alabama Power may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 4, 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2014 through March 31, 2015. It is anticipated that no adjustment will be made to Rate CNP PPA in 2015. As of December 31, 2014, Alabama Power had an under recovered certificated PPA balance of $56 million, of which $27 million is included in under recovered regulatory clause revenues and $29 million is included in deferred under recovered regulatory clause revenues in the balance sheet. | ||||||||||||
In 2011, the Alabama PSC approved and certificated a PPA of approximately 200 MWs of electricity from wind-powered generating facilities that became operational in 2012. In 2012, the Alabama PSC approved and certificated a second PPA of approximately 200 MWs of electricity from other wind-powered generating facilities which became operational in 2014. The terms of the PPAs permit Alabama Power to use the energy and retire the associated environmental attributes in service of its customers or to sell the environmental attributes, separately or bundled with energy. Alabama Power has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry's application of the NPNS exception to certain physical forward transactions in nodal markets was previously under review by the SEC at the request of the electric utility industry. In June 2014, the SEC requested the Financial Accounting Standards Board to address the issue through the Emerging Issues Task Force (EITF). Any accounting decisions will now be subject to EITF deliberations. The outcome of the EITF's deliberations cannot be determined at this time. If Alabama Power is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded. | ||||||||||||
Rate CNP Environmental allows for the recovery of Alabama Power's retail costs associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. There was no adjustment to Rate CNP Environmental in 2014. In August 2013, the Alabama PSC approved Alabama Power's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets previously being recovered through Rate RSE. The Rate CNP Environmental increase effective January 1, 2015 was 1.5%, or $75 million annually, based upon projected billings. As of December 31, 2014, Alabama Power had an under recovered environmental clause balance of $49 million, of which $47 million is included in under recovered regulatory clause revenues and $2 million is included in deferred under recovered regulatory clause revenues in the balance sheet. | ||||||||||||
Rate ECR | ||||||||||||
Alabama Power has established energy cost recovery rates under Alabama Power's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that Alabama Power leave in effect for 2015 the energy cost recovery rates which began in 2011. Therefore, the Rate ECR factor as of January 1, 2015 remained at 2.681 cents per KWH. Effective with billings beginning in January 2016, the Rate ECR factor will be 5.910 cents per KWH, absent a further order from the Alabama PSC. | ||||||||||||
Alabama Power's over recovered fuel costs at December 31, 2014 totaled $47 million as compared to over recovered fuel costs of $42 million at December 31, 2013. At December 31, 2014, $47 million is included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs. | ||||||||||||
Rate NDR | ||||||||||||
Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance Alabama Power's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. | ||||||||||||
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. | ||||||||||||
Environmental Accounting Order | ||||||||||||
Based on an order from the Alabama PSC, Alabama Power is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit's remaining useful life, as established prior to the decision regarding early retirement. | ||||||||||||
As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Alabama Power also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016. | ||||||||||||
In accordance with an accounting order from the Alabama PSC, Alabama Power will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized through Rate CNP Environmental over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on Southern Company's financial statements. | ||||||||||||
Nuclear Waste Fund Accounting Order | ||||||||||||
In November 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. In accordance with the court's order, the DOE submitted a proposal to the U.S. Congress to change the fee to zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. | ||||||||||||
On August 5, 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). At December 31, 2014, Alabama Power recorded an $8 million regulatory liability which is included in other regulatory liabilities deferred in the balance sheet. Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers, subject to the approval of the Alabama PSC. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Compliance and Pension Cost Accounting Order | ||||||||||||
In 2012, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. These deferred costs would have been amortized over a three-year period beginning in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the NRC, and (iii) NRC guidance addressing the readiness at nuclear facilities within the U.S. for severe events. | ||||||||||||
On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, including the $28 million of compliance and pension costs accumulated at December 31, 2014. This amortization expense was offset by the amortization of the regulatory liability for other cost of removal obligations. See "Cost of Removal Accounting Order" herein for additional information. The cost of removal accounting order requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders. | ||||||||||||
Non-Nuclear Outage Accounting Order | ||||||||||||
In August 2013, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. | ||||||||||||
On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, including the $95 million of non-nuclear outage costs accumulated at December 31, 2014. This amortization expense was reflected in other operations and maintenance and was offset by the amortization of the regulatory liability for other cost of removal obligations. See "Cost of Removal Accounting Order" herein for additional information. The cost of removal accounting order requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the non-nuclear outage accounting order. | ||||||||||||
Cost of Removal Accounting Order | ||||||||||||
In accordance with an accounting order issued on November 3, 2014 by the Alabama PSC, at December 31, 2014, Alabama Power fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances amortized as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, as discussed herein. | ||||||||||||
Non-Environmental Federal Mandated Costs Accounting Order | ||||||||||||
On December 9, 2014, pending the development of a new cost recovery mechanism, the Alabama PSC issued an accounting order authorizing the deferral as a regulatory asset of up to $50 million of costs associated with non-environmental federal mandates that would otherwise impact rates in 2015. | ||||||||||||
On February 17, 2015, Alabama Power filed a proposed modification to Rate CNP Environmental with the Alabama PSC to include compliance costs for both environmental and non-environmental mandates. The non-environmental costs that would be recovered through the revised mechanism concern laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. If approved as requested, the effective date for the revised mechanism would be March 20, 2015, upon which the regulatory asset balance would be reclassified to the under recovered balance for Rate CNP Environmental, and the related customer rates would not become effective before January 2016. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Georgia Power | ||||||||||||
Rate Plans | ||||||||||||
In December 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among Georgia Power, the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors, which was filed with the Georgia PSC in November 2013. | ||||||||||||
On January 1, 2014, in accordance with the 2013 ARP, Georgia Power increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) Environmental Compliance Cost Recovery (ECCR) tariff by approximately $25 million; (3) Demand-Side Management (DSM) tariffs by approximately $1 million; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million, for a total increase in base revenues of approximately $110 million. | ||||||||||||
On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved adjustments to traditional base, ECCR, DSM, and MFF tariffs effective January 1, 2015 as follows: | ||||||||||||
• | Traditional base tariffs by approximately $107 million to cover additional capacity costs; | |||||||||||
• | ECCR tariff by approximately $23 million; | |||||||||||
• | DSM tariffs by approximately $3 million; and | |||||||||||
• | MFF tariff by approximately $3 million to reflect the adjustments above. | |||||||||||
The sum of these adjustments resulted in a base revenue increase of approximately $136 million in 2015. | ||||||||||||
The 2016 base rate increase, which was approved in the 2013 ARP, will be determined through a compliance filing expected to be filed in late 2015, and will be subject to review by the Georgia PSC. | ||||||||||||
Under the 2013 ARP, Georgia Power's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by Georgia Power. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. However, if at any time during the term of the 2013 ARP, Georgia Power projects that its retail earnings will be below 10.00% for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff that would be used to adjust Georgia Power's earnings back to a 10.00% retail ROE. The Georgia PSC would have 90 days to rule on Georgia Power's request. The ICR tariff will expire at the earlier of January 1, 2017 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full rate case. In 2014, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power expects to refund to retail customers approximately $13 million in 2015, subject to review and approval by the Georgia PSC. | ||||||||||||
Except as provided above, Georgia Power will not file for a general base rate increase while the 2013 ARP is in effect. Georgia Power is required to file a general rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued. | ||||||||||||
Integrated Resource Plans | ||||||||||||
In July 2013, the Georgia PSC approved Georgia Power's latest triennial Integrated Resource Plan (2013 IRP) including Georgia Power's request to decertify 16 coal- and oil-fired units totaling 2,093 MWs. Several factors, including the cost to comply with existing and future environmental regulations, recent and forecasted economic conditions, and lower natural gas prices, contributed to the decision to close these units. | ||||||||||||
Plant Branch Units 3 and 4 (1,016 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) will be decertified and retired by April 16, 2015, the compliance date of the Mercury and Air Toxics Standards (MATS) rule. The decertification date of Plant Branch Unit 1 (250 MWs) was extended from December 31, 2013 as specified in the final order in the 2011 Integrated Resource Plan Update (2011 IRP Update) to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) were also approved and will be effective by April 16, 2016, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division in September 2013 to allow for necessary transmission system reliability improvements. In July 2013, the Georgia PSC approved the switch to natural gas as the primary fuel for Plant Yates Units 6 and 7. In September 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP Update in order to comply with the State of Georgia's Multi-Pollutant Rule. | ||||||||||||
In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years beginning in January 2014 and the amortization of any remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. The Georgia PSC deferred a decision regarding the appropriate recovery period for the costs associated with unusable materials and supplies remaining at the retiring plants to Georgia Power's next base rate case, which Georgia Power expects to file in 2016 (2016 Rate Case). In the 2013 IRP, the Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases. | ||||||||||||
On July 1, 2014, the Georgia PSC approved Georgia Power's request to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. Georgia Power expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan to be filed in 2016. Georgia Power plans to continue to operate the unit as needed until the MATS rule becomes effective in April 2015. | ||||||||||||
The decertification of these units and fuel conversions are not expected to have a material impact on Southern Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2016 Rate Case and future fuel cases and cannot be determined at this time. | ||||||||||||
Fuel Cost Recovery | ||||||||||||
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in Georgia Power's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, Georgia Power continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. Georgia Power's fuel cost recovery includes costs associated with a natural gas hedging program as revised and approved by the Georgia PSC in February 2013, requiring it to use options and hedges within a 24-month time horizon. See Note 11 under "Energy-Related Derivatives" for additional information. On January 20, 2015, the Georgia PSC approved the deferral of Georgia Power's next fuel case filing until at least June 30, 2015. | ||||||||||||
Georgia Power's under recovered fuel balance totaled approximately $199 million at December 31, 2014 and is included in current assets and other deferred charges and assets. At December 31, 2013, Georgia Power's over recovered fuel balance totaled approximately $58 million and was included in current liabilities and other deferred credits and liabilities. | ||||||||||||
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. | ||||||||||||
Storm Damage Recovery | ||||||||||||
Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, Georgia Power is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $98 million and $37 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $68 million and $7 million included in other regulatory assets, deferred, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Southern Company's financial statements. | ||||||||||||
Nuclear Construction | ||||||||||||
In 2008, Georgia Power, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. | ||||||||||||
Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and CB&I's The Shaw Group Inc., respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. | ||||||||||||
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds. | ||||||||||||
In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On December 16, 2014, the Georgia PSC approved an increase to the NCCR tariff of approximately $27 million effective January 1, 2015. | ||||||||||||
In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor has subsequently asserted related minimum damages (based on Georgia Power's ownership interest) of $113 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. Georgia Power has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions. | ||||||||||||
Georgia Power is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by Georgia Power increase by 5% or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. Georgia Power's eighth VCM report filed in February 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. | ||||||||||||
In September 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. In addition, financing costs on any construction-related costs in excess of the certified amount likely would be subject to recovery through AFUDC instead of the NCCR tariff. | ||||||||||||
The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion. | ||||||||||||
On January 29, 2015, Georgia Power announced that it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4). Georgia Power has not agreed to any changes to the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Georgia Power does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. | ||||||||||||
In addition, Georgia Power believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, Georgia Power expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay. | ||||||||||||
On February 27, 2015, Georgia Power filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requests approval for an additional $0.2 billion of construction capital costs incurred during that period and reflects the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs of approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay are included in the twelfth VCM report. Additionally, while Georgia Power has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report includes a requested amendment to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. | ||||||||||||
Georgia Power will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimates total associated financing costs during the construction period to be approximately $2.5 billion. | ||||||||||||
Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both. | ||||||||||||
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021. | ||||||||||||
Additional claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Gulf Power | ||||||||||||
Retail Base Rate Case | ||||||||||||
In December 2013, the Florida PSC voted to approve the Gulf Power Settlement Agreement among Gulf Power and all of the intervenors to the docketed proceeding with respect to Gulf Power's request to increase retail base rates. Under the terms of the Gulf Power Settlement Agreement, Gulf Power (1) increased base rates designed to produce an additional $35 million in annual revenues effective January 2014 and subsequently increased base rates designed to produce an additional $20 million in annual revenues effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) will accrue a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until Gulf Power's next base rate adjustment date or January 1, 2017, whichever comes first. | ||||||||||||
The Gulf Power Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period. | ||||||||||||
The Gulf Power Settlement Agreement also provides that Gulf Power may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in Gulf Power's next base rate case or next depreciation and dismantlement study proceeding, whichever comes first. As a result, Gulf Power recognized an $8.4 million reduction in depreciation expense in 2014. | ||||||||||||
Pursuant to the Gulf Power Settlement Agreement, Gulf Power may not request an increase in its retail base rates to be effective until after June 2017, unless Gulf Power's actual retail ROE falls below the authorized ROE range. | ||||||||||||
Integrated Coal Gasification Combined Cycle | ||||||||||||
Kemper IGCC Overview | ||||||||||||
Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by Mississippi Power and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. In connection with the Kemper IGCC, Mississippi Power constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery. | ||||||||||||
Kemper IGCC Schedule and Cost Estimate | ||||||||||||
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. | ||||||||||||
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245.3 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. | ||||||||||||
The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service on natural gas on August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. | ||||||||||||
Recovery of the Kemper IGCC cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) and costs subject to the cost cap remain subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of December 31, 2014, as adjusted for the Court's decision, are as follows: | ||||||||||||
Cost Category | 2010 | Current Estimate | Actual Costs at 12/31/2014 | |||||||||
Project Estimate(f) | ||||||||||||
(in billions) | ||||||||||||
Plant Subject to Cost Cap(a) | $ | 2.4 | $ | 4.93 | $ | 4.23 | ||||||
Lignite Mine and Equipment | 0.21 | 0.23 | 0.23 | |||||||||
CO2 Pipeline Facilities | 0.14 | 0.11 | 0.1 | |||||||||
AFUDC(b)(c) | 0.17 | 0.63 | 0.45 | |||||||||
Combined Cycle and Related Assets Placed in | — | 0.02 | 0 | |||||||||
Service – Incremental(d) | ||||||||||||
General Exceptions | 0.05 | 0.1 | 0.07 | |||||||||
Deferred Costs(c)(e) | — | 0.18 | 0.12 | |||||||||
Total Kemper IGCC(a)(c) | $ | 2.97 | $ | 6.2 | $ | 5.2 | ||||||
(a) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014 that are subject to the $2.88 billion cost cap and excludes post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(b) | Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." | |||||||||||
(c) | Amounts in the Current Estimate reflect estimated costs through March 31, 2016. | |||||||||||
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||
(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC. | |||||||||||
Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2014, $3.04 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.05 billion), $1.8 million in other property and investments, $44.7 million in fossil fuel stock, $32.5 million in materials and supplies, $147.7 million in other regulatory assets, $11.6 million in other deferred charges and assets, and $23.6 million in AROs in the balance sheet, with $1.1 million previously expensed. | ||||||||||||
Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Southern Company recorded pre-tax charges to income for revisions to the cost estimate of $868.0 million ($536.0 million after tax) and $1.2 billion ($729 million after tax) in 2014 and 2013, respectively. The increases to the cost estimate in 2014 primarily reflected costs related to extension of the project's schedule to ensure the required time for start-up activities and operational readiness, completion of construction, additional resources during start-up, and ongoing construction support during start-up and commissioning activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month. | ||||||||||||
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material. | ||||||||||||
Rate Recovery of Kemper IGCC Costs | ||||||||||||
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company's results of operations, financial condition, and liquidity. | ||||||||||||
2012 MPSC CPCN Order | ||||||||||||
The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the Rate Mitigation Plan (defined below) and other related proceedings during the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on the financial statements. | ||||||||||||
2013 Settlement Agreement | ||||||||||||
In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed Mississippi Power to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" below for additional information. | ||||||||||||
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in February 2013. Mississippi Power's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as approved by the Mississippi PSC. | ||||||||||||
The Court's decision did not impact Mississippi Power's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" below for additional information. | ||||||||||||
2013 MPSC Rate Order | ||||||||||||
Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014. For the period from March 2013 through December 31, 2014, $257.2 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. | ||||||||||||
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC and collect and defer the approved rates through the in-service date until directed to do otherwise by the Mississippi PSC. | ||||||||||||
On August 18, 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, with the current recognition as revenue of the related equity return on all assets placed in service and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order. | ||||||||||||
In addition, Mississippi Power's August 18, 2014 filing with the Mississippi PSC requested confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC and the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by Mississippi Power could have a material impact on the results of operations, financial condition, and liquidity of Southern Company. | ||||||||||||
2015 Mississippi Supreme Court Decision | ||||||||||||
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order filed by Thomas A. Blanton. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. The Court's ruling remands the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through December 31, 2014, Mississippi Power had collected $257.2 million through rates under the 2013 MPSC Rate Order. Any required refunds would also include carrying costs. The Court's decision will become legally effective upon the issuance of a mandate to the Mississippi PSC. Absent specific instruction from the Court, the Mississippi PSC will determine the method and timing of the refund. Mississippi Power is reviewing the Court's decision and expects to file a motion for rehearing which would stay the Court's mandate until either the case is reheard and decided or seven days after the Court issues its order denying Mississippi Power's request for rehearing. Mississippi Power is also evaluating its regulatory options. | ||||||||||||
Rate Mitigation Plan | ||||||||||||
In March 2013, Mississippi Power, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015. In the Rate Mitigation Plan, Mississippi Power proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, was integral to the Rate Mitigation Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Rate Mitigation Plan, Mississippi Power proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under Mississippi Power's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" for additional information. | ||||||||||||
To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" above for additional information. | ||||||||||||
In the event that the Mirror CWIP regulatory liability is refunded to customers prior to the in-service date of the Kemper IGCC and is, therefore, not available to mitigate rate impacts under the Rate Mitigation Plan, the Mississippi PSC does not approve a refund schedule that facilitates rate mitigation, or Mississippi Power withdraws the Rate Mitigation Plan, Mississippi Power would seek rate recovery through alternate means, which could include a traditional rate case. | ||||||||||||
In addition to current estimated costs at December 31, 2014 of $6.2 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC. | ||||||||||||
Prudence Reviews | ||||||||||||
The Mississippi PSC's review of Kemper IGCC costs is ongoing. On August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the MPUS. The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution. As a result of the Court's decision, Mississippi Power intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" for additional information. | ||||||||||||
Regulatory Assets and Liabilities | ||||||||||||
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service. | ||||||||||||
On August 18, 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of December 31, 2014, the regulatory asset balance associated with the Kemper IGCC was $147.7 million. The projected balance at March 31, 2016 is estimated to total approximately $269.8 million. The amortization period of 40 years proposed by Mississippi Power for any such costs approved for recovery remains subject to approval by the Mississippi PSC. | ||||||||||||
The 2013 MPSC Rate Order approved retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014. On February 12, 2015, the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. Mississippi Power is deferring the collections under the approved rates in the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. Mississippi Power is also accruing carrying costs on the unamortized balance of the Mirror CWIP regulatory liability for the benefit of retail customers. As of December 31, 2014, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $270.8 million. | ||||||||||||
See "2015 Mississippi Supreme Court Decision" for additional information. | ||||||||||||
See Note 1 under "Regulatory Assets and Liabilities" for additional information. | ||||||||||||
Lignite Mine and CO2 Pipeline Facilities | ||||||||||||
In conjunction with the Kemper IGCC, Mississippi Power will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013. | ||||||||||||
In 2010, Mississippi Power executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, Mississippi Power currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. | ||||||||||||
In addition, Mississippi Power has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event that Mississippi Power does not satisfy its contractual obligation with respect to deliveries of captured CO2 by May 11, 2015. While Mississippi Power has received no indication from either Denbury or Treetop of their intent to terminate their respective agreements, any termination could result in a material reduction in future chemical product sales revenues but is not expected to have a material financial impact on Southern Company to the extent Mississippi Power is not able to enter into other similar contractual arrangements. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Proposed Sale of Undivided Interest to SMEPA | ||||||||||||
In 2010, Mississippi Power and SMEPA entered into an APA whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the 2011 power supply agreement were $16.7 million in 2014. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014. | ||||||||||||
By letter agreement dated October 6, 2014, Mississippi Power and SMEPA agreed in principle on certain issues related to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The letter agreement contemplated certain amendments to the APA, which the parties anticipated to be incorporated into the APA on or before December 31, 2014. The parties agreed to further amend the APA as follows: (1) Mississippi Power agreed to cap at $2.88 billion the portion of the purchase price payable for development and construction costs, net of the Cost Cap Exceptions, title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the Kemper IGCC in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions, and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date. The letter agreement also provided for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service. | ||||||||||||
By letter dated December 18, 2014, SMEPA notified Mississippi Power that SMEPA decided not to extend the estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination. | ||||||||||||
The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase. | ||||||||||||
In 2012, on January 2, 2014, and on October 9, 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, Mississippi Power would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposits and SMEPA's ability to request a refund, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Baseload Act | ||||||||||||
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. In the 2015 Mississippi Supreme Court decision, the Court declined to rule on the constitutionality of the Baseload Act. See "Rate Recovery of Kemper IGCC Costs" herein for additional information. | ||||||||||||
Investment Tax Credits and Bonus Depreciation | ||||||||||||
The IRS allocated $279.0 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through December 31, 2014, Mississippi Power had recorded tax benefits totaling $276.4 million for the Phase II credits, of which approximately $210.0 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. Mississippi Power currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's proposed purchase of an undivided interest in the Kemper IGCC as described above. | ||||||||||||
On December 19, 2014, the Tax Increase Prevention Act of 2014 (TIPA) was signed into law. The TIPA retroactively extended several tax credits through 2014 and extended 50% bonus depreciation for property placed in service in 2014 (and for certain long-term production-period projects to be placed in service in 2015). The extension of 50% bonus depreciation had a positive impact on Southern Company's cash flows and, combined with bonus depreciation allowed in 2014 under the ATRA, resulted in approximately $130 million of positive cash flows related to the combined cycle and associated common facilities portion of the Kemper IGCC for the 2014 tax year. The estimated cash flow benefit of bonus depreciation related to TIPA is expected to be approximately $45 million to $50 million for the 2015 tax year. See "Rate Recovery of Kemper IGCC Costs – Rate Mitigation Plan" herein for additional information. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Section 174 Research and Experimental Deduction | ||||||||||||
Southern Company reduced tax payments for 2014 and included in its 2013 consolidated federal income tax return deductions for research and experimental (R&E) expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Southern Company recorded an unrecognized tax benefit of approximately $160 million as of December 31, 2014. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||
Other Matters | ||||||||||||
Sierra Club Settlement Agreement | ||||||||||||
On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the flue gas desulfurization system (scrubber) project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw all appeals associated with certification of the Kemper IGCC and the Plant Daniel Units 1 and 2 scrubber project, which the applicable courts subsequently granted. | ||||||||||||
Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, Mississippi Power paid $7 million in 2014, recognized in other income (expense), net in Southern Company's statement of income. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. | ||||||||||||
Alabama Power [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS | |||||||||||
General Litigation Matters | ||||||||||||
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. | ||||||||||||
Environmental Matters | ||||||||||||
New Source Review Actions | ||||||||||||
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against the Company alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by Mississippi Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against the Company (including claims involving a unit co-owned by Mississippi Power) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for the Company on all remaining claims and dismissal of the case with prejudice in 2011. In September 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of the Company, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings. | ||||||||||||
The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Environmental Remediation | ||||||||||||
The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company could incur substantial costs to clean up properties. The Company conducts studies to determine the extent of any required cleanup and has recognized in its financial statements the costs to clean up known sites. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The Company may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. | ||||||||||||
Nuclear Fuel Disposal Costs | ||||||||||||
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into a contract with the Company that requires the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Farley beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company has pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract. | ||||||||||||
As a result of the first lawsuit, the Company recovered approximately $17 million, representing the vast majority of the Company's direct costs of the expansion of spent nuclear fuel storage facilities at Plant Farley from 1998 through 2004. In 2012, the award was credited to cost of service for the benefit of customers. | ||||||||||||
On December 12, 2014, the Court of Federal Claims entered a judgment in favor of the Company in its second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. The Company was awarded approximately $26 million. No amounts have been recognized in the financial statements as of December 31, 2014. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected. | ||||||||||||
On March 4, 2014, the Company filed a third lawsuit against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Farley for the period from January 1, 2011 through December 31, 2013. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2014 for any potential recoveries from the third lawsuit. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected. | ||||||||||||
At Plant Farley, on-site dry spent fuel storage facilities are operational and can be expanded to accommodate spent fuel through the expected life of the plant. | ||||||||||||
Retail Regulatory Matters | ||||||||||||
Rate RSE | ||||||||||||
Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. If the Company's actual retail return is above the allowed weighted cost of equity (WCE) range, customer refunds will be required; however, there is no provision for additional customer billings should the actual retail return fall below the WCE range. Prior to 2014, retail rates remained unchanged when the retail ROE was projected to be between 13.0% and 14.5%. | ||||||||||||
During 2013, the Alabama PSC held public proceedings regarding the operation and utilization of Rate RSE. In August 2013, the Alabama PSC voted to issue a report on Rate RSE that found that the Company's Rate RSE mechanism continues to be just and reasonable to customers and the Company, but recommended the Company modify Rate RSE as follows: | ||||||||||||
• | Eliminate the provision of Rate RSE establishing an allowed range of ROE. | |||||||||||
• | Eliminate the provision of Rate RSE limiting the Company's capital structure to an allowed equity ratio of 45%. | |||||||||||
• | Replace these two provisions with a provision that establishes rates based upon the WCE range of 5.75% to 6.21%, with an adjusting point of 5.98%. If calculated under the previous Rate RSE provisions, the resulting WCE would range from 5.85% to 6.53%, with an adjusting point of 6.19%. | |||||||||||
• | Provide eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCE adjusting point if the Company (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey. | |||||||||||
Substantially all other provisions of Rate RSE were unchanged. | ||||||||||||
In August 2013, the Company filed its consent to these recommendations with the Alabama PSC. The changes became effective for calendar year 2014. In November 2013, the Company made its Rate RSE submission to the Alabama PSC of projected data for calendar year 2014; projected earnings were within the specified WCE range and, therefore, retail rates under Rate RSE remained unchanged for 2014. In 2012 and 2013, retail rates under Rate RSE remained unchanged from 2011. Under the terms of Rate RSE, the maximum possible increase for 2015 is 5.00%. | ||||||||||||
On December 1, 2014, the Company submitted the required annual filing under Rate RSE to the Alabama PSC. The Rate RSE increase was 3.49%, or $181 million annually, effective January 1, 2015. The revenue adjustment includes the performance based adder of 0.07%. Under the terms of Rate RSE, the maximum increase for 2016 cannot exceed 4.51%. | ||||||||||||
Rate CNP | ||||||||||||
The Company's retail rates, approved by the Alabama PSC, provide for adjustments to recognize the placing of new generating facilities into retail service under Rate CNP. The Company may also recover retail costs associated with certificated PPAs under Rate CNP PPA. On March 4, 2014, the Alabama PSC issued a consent order that the Company leave in effect the current Rate CNP PPA factor for billings for the period April 1, 2014 through March 31, 2015. It is anticipated that no adjustment will be made to Rate CNP PPA in 2015. As of December 31, 2014, the Company had an under recovered certificated PPA balance of $56 million, of which $27 million is included in under recovered regulatory clause revenues and $29 million is included in deferred under recovered regulatory clause revenues in the balance sheet. | ||||||||||||
In 2011, the Alabama PSC approved and certificated a PPA of approximately 200 MWs of electricity from wind-powered generating facilities that became operational in 2012. In 2012, the Alabama PSC approved and certificated a second PPA of approximately 200 MWs of electricity from other wind-powered generating facilities which became operational in 2014. The terms of the PPAs permit the Company to use the energy and retire the associated environmental attributes in service of its customers or to sell the environmental attributes, separately or bundled with energy. The Company has elected the normal purchase normal sale (NPNS) scope exception under the derivative accounting rules for its two wind PPAs, which total approximately 400 MWs. The NPNS exception allows the PPAs to be recorded at a cost, rather than fair value, basis. The industry's application of the NPNS exception to certain physical forward transactions in nodal markets was previously under review by the SEC at the request of the electric utility industry. In June 2014, the SEC requested the Financial Accounting Standards Board to address the issue through the Emerging Issues Task Force (EITF). Any accounting decisions will now be subject to EITF deliberations. The outcome of the EITF's deliberations cannot be determined at this time. If the Company is ultimately required to record these PPAs at fair value, an offsetting regulatory asset or regulatory liability will be recorded. | ||||||||||||
Rate CNP Environmental allows for the recovery of the Company's retail costs associated with environmental laws, regulations, or other such mandates. Rate CNP Environmental is based on forward-looking information and provides for the recovery of these costs pursuant to a factor that is calculated annually. Environmental costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. There was no adjustment to Rate CNP Environmental in 2014. In August 2013, the Alabama PSC approved the Company's petition requesting a revision to Rate CNP Environmental that allows recovery of costs related to pre-2005 environmental assets previously being recovered through Rate RSE. The Rate CNP Environmental increase effective January 1, 2015 was 1.5%, or $75 million annually, based upon projected billings. As of December 31, 2014, the Company had an under recovered environmental clause balance of $49 million, of which $47 million is included in under recovered regulatory clause revenues and $2 million is included in deferred under recovered regulatory clause revenues in the balance sheet. | ||||||||||||
Rate ECR | ||||||||||||
The Company has established energy cost recovery rates under the Company's Rate ECR as approved by the Alabama PSC. Rates are based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed give rise to the over or under recovered amounts recorded as regulatory assets or liabilities. The Company, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on the Company's net income, but will impact operating cash flows. Currently, the Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH. In December 2014, the Alabama PSC issued a consent order that the Company leave in effect for 2015 the energy cost recovery rates which began in 2011. Therefore, the Rate ECR factor as of January 1, 2015 remained at 2.681 cents per KWH. Effective with billings beginning in January 2016, the Rate ECR factor will be 5.910 cents per KWH, absent a further order from the Alabama PSC. | ||||||||||||
The Company's over recovered fuel costs at December 31, 2014 totaled $47 million as compared to over recovered fuel costs of $42 million at December 31, 2013. At December 31, 2014, $47 million is included in deferred over recovered regulatory clause revenues. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a material impact on the timing of any recovery or return of fuel costs. | ||||||||||||
Rate NDR | ||||||||||||
Based on an order from the Alabama PSC, the Company maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives the Company authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. The Company has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. The Company may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR will enhance the Company's ability to deal with the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. | ||||||||||||
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows. | ||||||||||||
Environmental Accounting Order | ||||||||||||
Based on an order from the Alabama PSC, the Company is allowed to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements caused by environmental regulations. These costs would be amortized over the affected unit's remaining useful life, as established prior to the decision regarding early retirement. | ||||||||||||
As part of its environmental compliance strategy, the Company plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of the Company's approximately 12,200 MWs of generating capacity. The Company also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, the Company expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016. | ||||||||||||
In accordance with an accounting order from the Alabama PSC, the Company will transfer the unrecovered plant asset balances to a regulatory asset at their respective retirement dates. The regulatory asset will be amortized through Rate CNP Environmental over the remaining useful lives, as established prior to the decision for retirement. As a result, these decisions will not have a significant impact on the Company's financial statements. | ||||||||||||
Nuclear Waste Fund Accounting Order | ||||||||||||
In November 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. In accordance with the court's order, the DOE submitted a proposal to the U.S. Congress to change the fee to zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. | ||||||||||||
On August 5, 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, the Company is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). At December 31, 2014, the Company recorded an $8 million regulatory liability which is included in other regulatory liabilities deferred in the balance sheet. Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers, subject to the approval of the Alabama PSC. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Compliance and Pension Cost Accounting Order | ||||||||||||
In 2012, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain compliance-related operations and maintenance expenditures for the years 2013 through 2017, as well as the incremental increase in operations expense related to pension cost for 2013. These deferred costs would have been amortized over a three-year period beginning in January 2015. The compliance related expenditures were related to (i) standards addressing Critical Infrastructure Protection issued by the North American Electric Reliability Corporation, (ii) cyber security requirements issued by the NRC, and (iii) NRC guidance addressing the readiness at nuclear facilities within the U.S. for severe events. | ||||||||||||
On November 3, 2014, the Alabama PSC issued an accounting order authorizing the Company to fully amortize the balances in certain regulatory asset accounts, including the $28 million of compliance and pension costs accumulated at December 31, 2014. This amortization expense was offset by the amortization of the regulatory liability for other cost of removal obligations. See "Cost of Removal Accounting Order" herein for additional information. The cost of removal accounting order requires the Company to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order. Consequently, the Company will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders. | ||||||||||||
Non-Nuclear Outage Accounting Order | ||||||||||||
In August 2013, the Alabama PSC approved an accounting order to defer to a regulatory asset account certain operations and maintenance expenses associated with planned outages at non-nuclear generation facilities in 2014 and to amortize those expenses over a three-year period beginning in 2015. | ||||||||||||
On November 3, 2014, the Alabama PSC issued an accounting order authorizing the Company to fully amortize the balances in certain regulatory asset accounts, including the $95 million of non-nuclear outage costs accumulated at December 31, 2014. This amortization expense was reflected in other operations and maintenance and was offset by the amortization of the regulatory liability for other cost of removal obligations. See "Cost of Removal Accounting Order" herein for additional information. The cost of removal accounting order requires the Company to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the non-nuclear outage accounting order. | ||||||||||||
Cost of Removal Accounting Order | ||||||||||||
In accordance with an accounting order issued on November 3, 2014 by the Alabama PSC, at December 31, 2014, the Company fully amortized the balance of $123 million in certain regulatory asset accounts and offset this amortization expense with the amortization of $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances amortized as of December 31, 2014 represented costs previously deferred under a compliance and pension cost accounting order as well as a non-nuclear outage accounting order, as discussed herein. | ||||||||||||
Non-Environmental Federal Mandated Costs Accounting Order | ||||||||||||
On December 9, 2014, pending the development of a new cost recovery mechanism, the Alabama PSC issued an accounting order authorizing the deferral as a regulatory asset of up to $50 million of costs associated with non-environmental federal mandates that would otherwise impact rates in 2015. | ||||||||||||
On February 17, 2015, the Company filed a proposed modification to Rate CNP Environmental with the Alabama PSC to include compliance costs for both environmental and non-environmental mandates. The non-environmental costs that would be recovered through the revised mechanism concern laws, regulations, and other mandates directed at the utility industry involving the security, reliability, safety, sustainability, or similar considerations impacting the Company's facilities or operations. If approved as requested, the effective date for the revised mechanism would be March 20, 2015, upon which the regulatory asset balance would be reclassified to the under recovered balance for Rate CNP Environmental, and the related customer rates would not become effective before January 2016. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Georgia Power [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS | |||||||||||
General Litigation Matters | ||||||||||||
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. | ||||||||||||
Environmental Matters | ||||||||||||
New Source Review Actions | ||||||||||||
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against the Company alleging violations of the New Source Review provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by Gulf Power. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. The case against the Company (including claims related to a unit co-owned by Gulf Power) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. | ||||||||||||
The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Environmental Remediation | ||||||||||||
The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. See Note 1 under "Environmental Remediation Recovery" for additional information. | ||||||||||||
The Company has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated. | ||||||||||||
The Company and numerous other entities have been designated by the EPA as PRPs at the Ward Transformer Superfund site located in Raleigh, North Carolina. In 2011, the EPA issued a Unilateral Administrative Order (UAO) to the Company and 22 other parties, ordering specific remedial action of certain areas at the site. Later in 2011, the Company filed a response with the EPA stating it has sufficient cause to believe it is not a liable party under CERCLA. The EPA notified the Company in 2011 that it is considering enforcement options against the Company and other non-complying UAO recipients. If the EPA pursues enforcement actions and the court determines that a respondent failed to comply with the UAO without sufficient cause, the EPA may also seek civil penalties of up to $37,500 per day for the violation and punitive damages of up to three times the costs incurred by the EPA as a result of the party's failure to comply with the UAO. | ||||||||||||
In addition to the EPA's action at this site, the Company, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In February 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted the Company's summary judgment motion, ruling that the Company has no liability in the private action. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit. | ||||||||||||
The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of the Company's regulatory treatment for environmental remediation expenses described in Note 1 under "Environmental Remediation Recovery," these matters are not expected to have a material impact on the Company's financial statements. | ||||||||||||
Nuclear Fuel Disposal Costs | ||||||||||||
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with the Company that require the DOE to dispose of spent nuclear fuel and high level radioactive waste generated at Plant Hatch and Plant Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence the performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, the Company pursued and continues to pursue legal remedies against the U.S. government for its partial breach of contract. | ||||||||||||
As a result of its first lawsuit, the Company recovered approximately $27 million, based on its ownership interests, representing the vast majority of the Company's direct costs of the expansion of spent nuclear fuel storage facilities at Plant Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. The proceeds were received in 2012 and credited to the Company accounts where the original costs were charged and were used to reduce rate base, fuel, and cost of service for the benefit of customers. | ||||||||||||
On December 12, 2014, the Court of Federal Claims entered a judgment in favor of the Company in its second spent nuclear fuel lawsuit seeking damages for the period from January 1, 2005 through December 31, 2010. The Company was awarded approximately $18 million, based on its ownership interests. No amounts have been recognized in the financial statements as of December 31, 2014. The final outcome of this matter cannot be determined at this time; however, no material impact on the Company's net income is expected. | ||||||||||||
On March 4, 2014, the Company filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plant Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2014 for any potential recoveries from the additional lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on the Company's net income is expected as a significant portion of any damage amounts collected from the government is expected to be credited to the Company accounts where the original costs were charged and used to reduce rate base, fuel, and cost of service for the benefit of customers. | ||||||||||||
On-site dry spent fuel storage facilities are operational at Plant Vogtle Units 1 and 2 and Plant Hatch. Facilities at the plants can be expanded to accommodate spent fuel through the expected life of each plant. | ||||||||||||
Retail Regulatory Matters | ||||||||||||
Rate Plans | ||||||||||||
In December 2013, the Georgia PSC voted to approve the 2013 ARP. The 2013 ARP reflects the settlement agreement among the Company, the Georgia PSC's Public Interest Advocacy Staff, and 11 of the 13 intervenors, which was filed with the Georgia PSC in November 2013. | ||||||||||||
On January 1, 2014, in accordance with the 2013 ARP, the Company increased its tariffs as follows: (1) traditional base tariff rates by approximately $80 million; (2) ECCR tariff by approximately $25 million; (3) Demand-Side Management (DSM) tariffs by approximately $1 million; and (4) Municipal Franchise Fee (MFF) tariff by approximately $4 million, for a total increase in base revenues of approximately $110 million. | ||||||||||||
On February 19, 2015, in accordance with the 2013 ARP, the Georgia PSC approved adjustments to traditional base, ECCR, DSM, and MFF tariffs effective January 1, 2015 as follows: | ||||||||||||
• | Traditional base tariffs by approximately $107 million to cover additional capacity costs; | |||||||||||
• | ECCR tariff by approximately $23 million; | |||||||||||
• | DSM tariffs by approximately $3 million; and | |||||||||||
• | MFF tariff by approximately $3 million to reflect the adjustments above. | |||||||||||
The sum of these adjustments resulted in a base revenue increase of approximately $136 million in 2015. | ||||||||||||
The 2016 base rate increase, which was approved in the 2013 ARP, will be determined through a compliance filing expected to be filed in late 2015, and will be subject to review by the Georgia PSC. | ||||||||||||
Under the 2013 ARP, the Company's retail ROE is set at 10.95% and earnings are evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% will be directly refunded to customers, with the remaining one-third retained by the Company. There will be no recovery of any earnings shortfall below 10.00% on an actual basis. However, if at any time during the term of the 2013 ARP, the Company projects that its retail earnings will be below 10.00% for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff that would be used to adjust the Company's earnings back to a 10.00% retail ROE. The Georgia PSC would have 90 days to rule on the Company's request. The ICR tariff will expire at the earlier of January 1, 2017 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, the Company may file a full rate case. In 2014, the Company's retail ROE exceeded 12.00%, and the Company expects to refund to retail customers approximately $13 million in 2015, subject to review and approval by the Georgia PSC. | ||||||||||||
Except as provided above, the Company will not file for a general base rate increase while the 2013 ARP is in effect. The Company is required to file a general rate case by July 1, 2016, in response to which the Georgia PSC would be expected to determine whether the 2013 ARP should be continued, modified, or discontinued. | ||||||||||||
Integrated Resource Plans | ||||||||||||
In July 2013, the Georgia PSC approved the Company's latest triennial Integrated Resource Plan (2013 IRP) including the Company's request to decertify 16 coal- and oil-fired units totaling 2,093 MWs. Several factors, including the cost to comply with existing and future environmental regulations, recent and forecasted economic conditions, and lower natural gas prices, contributed to the decision to close these units. | ||||||||||||
Plant Branch Units 3 and 4 (1,016 MWs), Plant Yates Units 1 through 5 (579 MWs), and Plant McManus Units 1 and 2 (122 MWs) will be decertified and retired by April 16, 2015, the compliance date of the Mercury and Air Toxics Standards (MATS) rule. The decertification date of Plant Branch Unit 1 (250 MWs) was extended from December 31, 2013 as specified in the final order in the 2011 Integrated Resource Plan Update (2011 IRP Update) to coincide with the decertification date of Plant Branch Units 3 and 4. The decertification and retirement of Plant Kraft Units 1 through 4 (316 MWs) were also approved and will be effective by April 16, 2016, based on a one-year extension of the MATS rule compliance date that was approved by the State of Georgia Environmental Protection Division in September 2013 to allow for necessary transmission system reliability improvements. In July 2013, the Georgia PSC approved the switch to natural gas as the primary fuel for Plant Yates Units 6 and 7. In September 2013, Plant Branch Unit 2 (319 MWs) was retired as approved by the Georgia PSC in the 2011 IRP Update in order to comply with the State of Georgia's Multi-Pollutant Rule. | ||||||||||||
In the 2013 ARP, the Georgia PSC approved the amortization of the CWIP balances related to environmental projects that will not be completed at Plant Branch Units 1 through 4 and Plant Yates Units 6 and 7 over nine years beginning in January 2014 and the amortization of any remaining net book values of Plant Branch Unit 2 from October 2013 to December 2022, Plant Branch Unit 1 from May 2015 to December 2020, Plant Branch Unit 3 from May 2015 to December 2023, and Plant Branch Unit 4 from May 2015 to December 2024. The Georgia PSC deferred a decision regarding the appropriate recovery period for the costs associated with unusable materials and supplies remaining at the retiring plants to the Company's next base rate case, which the Company expects to file in 2016 (2016 Rate Case). In the 2013 IRP, the Georgia PSC also deferred decisions regarding the recovery of any fuel related costs that could be incurred in connection with the retirement units to be addressed in future fuel cases. | ||||||||||||
On July 1, 2014, the Georgia PSC approved the Company's request to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. The Company expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan to be filed in 2016. The Company plans to continue to operate the unit as needed until the MATS rule becomes effective in April 2015. | ||||||||||||
The decertification of these units and fuel conversions are not expected to have a material impact on the Company's financial statements; however, the ultimate outcome depends on the Georgia PSC's order in the 2016 Rate Case and future fuel cases and cannot be determined at this time. | ||||||||||||
Fuel Cost Recovery | ||||||||||||
The Company has established fuel cost recovery rates approved by the Georgia PSC. The Georgia PSC approved a reduction in the Company's total annual billings of approximately $567 million effective June 1, 2012, with an additional $122 million reduction effective January 1, 2013 through June 1, 2014. Under an Interim Fuel Rider, the Company continues to be allowed to adjust its fuel cost recovery rates prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million. The Company's fuel cost recovery includes costs associated with a natural gas hedging program as revised and approved by the Georgia PSC in February 2013, requiring it to use options and hedges within a 24-month time horizon. See Note 11 under "Energy-Related Derivatives" for additional information. On January 20, 2015, the Georgia PSC approved the deferral of the Company's next fuel case filing until at least June 30, 2015. | ||||||||||||
The Company's under recovered fuel balance totaled approximately $199 million at December 31, 2014 and is included in current assets and other deferred charges and assets. At December 31, 2013, the Company's over recovered fuel balance totaled approximately $58 million and was included in current liabilities and other deferred credits and liabilities. | ||||||||||||
Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on the Company's revenues or net income, but will affect cash flow. | ||||||||||||
Nuclear Construction | ||||||||||||
In 2008, the Company, acting for itself and as agent for Oglethorpe Power Corporation (OPC), the Municipal Electric Authority of Georgia (MEAG Power), and the City of Dalton, Georgia (Dalton), acting by and through its Board of Water, Light, and Sinking Fund Commissioners (collectively, Vogtle Owners), entered into an agreement with a consortium consisting of Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc., a subsidiary of The Shaw Group Inc., which was acquired by Chicago Bridge & Iron Company N.V. (CB&I) (collectively, Contractor), pursuant to which the Contractor agreed to design, engineer, procure, construct, and test two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities at Plant Vogtle (Vogtle 3 and 4 Agreement). Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Vogtle Owners for schedule and performance liquidated damages and warranty claims is subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to the Company (based on the Company's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. The Company's proportionate share is 45.7%. | ||||||||||||
Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and CB&I's The Shaw Group Inc., respectively. In the event of certain credit rating downgrades of any Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. | ||||||||||||
In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds. | ||||||||||||
In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows the Company to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On December 16, 2014, the Georgia PSC approved an increase to the NCCR tariff of approximately $27 million effective January 1, 2015. | ||||||||||||
In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, the Company and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against the Company and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to the Company (based on the Company's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations; however, the Contractor has subsequently asserted related minimum damages (based on the Company's ownership interest) of $113 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these allegations, any of which could be substantial. The Company has not agreed to the proposed cost or to any changes to the guaranteed substantial completion dates or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and the Company intends to vigorously defend the positions of the Vogtle Owners. The Company also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions. | ||||||||||||
The Company is required to file semi-annual Vogtle Construction Monitoring (VCM) reports with the Georgia PSC by February 28 and August 31 each year. If the projected certified construction capital costs to be borne by the Company increase by 5% or the projected in-service dates are significantly extended, the Company is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. The Company's eighth VCM report filed in February 2013 requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 and the fourth quarter 2018 for Plant Vogtle Units 3 and 4, respectively. | ||||||||||||
In September 2013, the Georgia PSC approved a stipulation (2013 Stipulation) entered into by the Company and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and the Company. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by the Company in excess of the certified amount will be included in rate base, provided the Company shows the costs to be reasonable and prudent. In addition, financing costs on any construction-related costs in excess of the certified amount likely would be subject to recovery through AFUDC instead of the NCCR tariff. | ||||||||||||
The Georgia PSC has approved eleven VCM reports covering the periods through June 30, 2014, including construction capital costs incurred, which through that date totaled $2.8 billion. | ||||||||||||
On January 29, 2015, the Company announced that it was notified by the Contractor of the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4, which would incrementally delay the previously disclosed estimated in-service dates by 18 months (from the fourth quarter of 2017 to the second quarter of 2019 for Unit 3 and from the fourth quarter of 2018 to the second quarter of 2020 for Unit 4). The Company has not agreed to any changes to the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. The Company does not believe that the Contractor's revised forecast reflects all efforts that may be possible to mitigate the Contractor's delay. | ||||||||||||
In addition, the Company believes that, pursuant to the Vogtle 3 and 4 Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be material) and that the Vogtle Owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017 for Plant Vogtle Units 3 and 4, respectively. Consistent with the Contractor's position in the pending litigation described above, the Company expects the Contractor to contest any claims for liquidated damages and to assert that the Vogtle Owners are responsible for additional costs related to the Contractor's delay. | ||||||||||||
On February 27, 2015, the Company filed its twelfth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2014, which requests approval for an additional $0.2 billion of construction capital costs incurred during that period and reflects the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 as well as additional estimated owner-related costs of approximately $10 million per month expected to result from the Contractor's proposed 18-month delay, including property taxes, oversight costs, compliance costs, and other operational readiness costs. No Contractor costs related to the Contractor's proposed 18-month delay are included in the twelfth VCM report. Additionally, while the Company has not agreed to any change to the guaranteed substantial completion dates, the twelfth VCM report includes a requested amendment to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast, to include the estimated owner's costs associated with the proposed 18-month Contractor delay, and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. | ||||||||||||
The Company will continue to incur financing costs of approximately $30 million per month until Plant Vogtle Units 3 and 4 are placed in service. The twelfth VCM report estimates total associated financing costs during the construction period to be approximately $2.5 billion. | ||||||||||||
Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both. | ||||||||||||
As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021. | ||||||||||||
Additional claims by the Contractor or the Company (on behalf of the Vogtle Owners) are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement, but also may be resolved through litigation. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Nuclear Waste Fund Fee | ||||||||||||
In November 2013, the U.S. District Court for the District of Columbia ordered the DOE to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the DOE either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved the Company's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider to the Company's fuel tariffs became effective July 1, 2014. | ||||||||||||
Gulf Power [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS | |||||||||||
General Litigation Matters | ||||||||||||
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. | ||||||||||||
Environmental Matters | ||||||||||||
New Source Review Actions | ||||||||||||
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Georgia Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by the Company. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. These actions were filed concurrently with the issuance of notices of violation of the NSR provisions to the Company with respect to the Company's Plant Crist. The case against Georgia Power (including claims related to a unit co-owned by the Company) has been administratively closed in the U.S. District Court for the Northern District of Georgia since 2001. | ||||||||||||
The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Environmental Remediation | ||||||||||||
The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company received authority from the Florida PSC to recover approved environmental compliance costs through the environmental cost recovery clause. The Florida PSC reviews costs and adjusts rates up or down annually. | ||||||||||||
The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable. At December 31, 2014, the Company's environmental remediation liability included estimated costs of environmental remediation projects of approximately $48.3 million. For 2014, approximately $4.5 million was included in under recovered regulatory clause revenues and other current liabilities, and approximately $43.7 million was included in other regulatory assets, deferred and other deferred credits and liabilities. These estimated costs relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at the Company's substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through the Company's environmental cost recovery clause; therefore, these liabilities have no impact on net income. | ||||||||||||
The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, the Company does not believe that additional liabilities, if any, at these sites would be material to the Company's financial statements. | ||||||||||||
Retail Regulatory Matters | ||||||||||||
The Company's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. The Company's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through the Company's base rates. | ||||||||||||
Retail Base Rate Case | ||||||||||||
In December 2013, the Florida PSC voted to approve the Settlement Agreement among the Company and all of the intervenors to the docketed proceeding with respect to the Company's request to increase retail base rates. Under the terms of the Settlement Agreement, the Company (1) increased base rates designed to produce an additional $35 million in annual revenues effective January 2014 and subsequently increased base rates designed to produce an additional $20 million in annual revenues effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); and (3) will accrue a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first. | ||||||||||||
The Settlement Agreement also includes a self-executing adjustment mechanism that will increase the authorized ROE midpoint and range by 25 basis points in the event the 30-year treasury yield rate increases by an average of at least 75 basis points above 3.7947% for a consecutive six-month period. | ||||||||||||
The Settlement Agreement also provides that the Company may reduce depreciation expense and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized ROE range then in effect. Recovery of the regulatory asset will occur over a period to be determined by the Florida PSC in the Company's next base rate case or next depreciation and dismantlement study proceeding, whichever comes first. As a result, the Company recognized an $8.4 million reduction in depreciation expense in 2014. | ||||||||||||
Pursuant to the Settlement Agreement, the Company may not request an increase in its retail base rates to be effective until after June 2017, unless the Company's actual retail ROE falls below the authorized ROE range. | ||||||||||||
Cost Recovery Clauses | ||||||||||||
On October 22, 2014, the Florida PSC approved the Company's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2015. The net effect of the approved changes is an expected $41.2 million increase in annual revenue for 2015. The increased revenues will not have a significant impact on net income since most of the revenues will be offset by expenses. | ||||||||||||
Revenues for all cost recovery clauses, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor for fuel and purchased power will have no significant effect on the Company's revenues or net income, but will affect annual cash flow. The recovery provisions for environmental compliance and energy conservation include related expenses and a return on net average investment. | ||||||||||||
Retail Fuel Cost Recovery | ||||||||||||
The Company has established fuel cost recovery rates as approved by the Florida PSC. If, at any time during the year, the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested for 2014. | ||||||||||||
At December 31, 2014 and 2013, the under recovered fuel balance was approximately $39.9 million and $21.0 million, respectively, which is included in under recovered regulatory clause revenues in the balance sheets. | ||||||||||||
Purchased Power Capacity Recovery | ||||||||||||
The Company has established purchased power capacity recovery cost rates as approved by the Florida PSC. If the projected year-end purchased power capacity cost over or under recovery balance exceeds 10% of the projected purchased power capacity revenue applicable for the period, the Company is required to notify the Florida PSC and indicate if an adjustment to the purchased power capacity cost recovery factor is being requested. | ||||||||||||
At December 31, 2014 and 2013, the under recovered purchased power capacity balance was approximately $0.3 million and $2.8 million, respectively, which is included in under recovered regulatory clause revenues in the balance sheets. | ||||||||||||
Environmental Cost Recovery | ||||||||||||
The Florida Legislature adopted legislation for an environmental cost recovery clause, which allows an electric utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Such environmental costs include operations and maintenance expenses, emissions allowance expense, depreciation, and a return on net average investment. This legislation also allows recovery of costs incurred as a result of an agreement between the Company and the FDEP for the purpose of ensuring compliance with ozone ambient air quality standards adopted by the EPA. | ||||||||||||
In 2007, the Florida PSC voted to approve a stipulation among the Company, the Office of Public Counsel, and the Florida Industrial Power Users Group regarding the Company's plan for complying with certain federal and state regulations addressing air quality. The Company's environmental compliance plan as filed in 2007 contemplated implementation of specific projects identified in the plan from 2007 through 2018. The Florida PSC's approval of the stipulation also required the Company to file annual updates to the plan and outlined a process for approval of additional elements in the plan when they became committed projects. In the 2010 update filing, the Company identified several elements of the updated plan that the Company had decided to implement. Following the process outlined in the original approved stipulation, these additional projects were approved by the Florida PSC later in 2010. The Florida PSC acknowledged that the costs of the approved projects associated with the Company's Clean Air Interstate Rule and Clean Air Visibility Rule compliance plans are eligible for recovery through the environmental cost recovery clause. | ||||||||||||
Annually, the Company seeks recovery of projected costs including any true-up amounts from prior periods. At December 31, 2014 and 2013, the under recovered environmental balance was approximately $9.8 million and $14.4 million, respectively, which is included in under recovered regulatory clause revenues in the balance sheets. | ||||||||||||
In 2012, the Mississippi PSC approved Mississippi Power's request for a certificate of public convenience and necessity to construct a scrubber on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and the Company, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with the Company's portion being $330 million, excluding AFUDC, and it is scheduled for completion in December 2015. The Company's portion of the cost is expected to be recovered through the environmental cost recovery clause. On August 28, 2014, the Chancery Court of Harrison County, Mississippi dismissed an appeal by the Sierra Club related to the construction of the scrubber on Plant Daniel Units 1 and 2. | ||||||||||||
Energy Conservation Cost Recovery | ||||||||||||
Every five years, the Florida PSC establishes new numeric conservation goals covering a 10-year period for utilities to reduce annual energy and seasonal peak demand using demand-side management (DSM) programs. After the goals are established, utilities develop plans and programs to meet the approved goals. The costs for these programs are recovered through rates established annually in the energy conservation cost recovery (ECCR) clause. | ||||||||||||
At December 31, 2014 and 2013, the under recovered energy conservation balance was approximately $2.6 million and $7.0 million, respectively, which is included in under recovered regulatory clause revenues in the balance sheets. | ||||||||||||
Mississippi Power [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS | |||||||||||
General Litigation Matters | ||||||||||||
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. | ||||||||||||
Environmental Matters | ||||||||||||
New Source Review Actions | ||||||||||||
As part of a nationwide enforcement initiative against the electric utility industry which began in 1999, the EPA brought civil enforcement actions in federal district court against Alabama Power alleging violations of the New Source Review (NSR) provisions of the Clean Air Act at certain coal-fired electric generating units, including a unit co-owned by the Company. These civil actions seek penalties and injunctive relief, including orders requiring installation of the best available control technologies at the affected units. These actions were filed concurrently with the issuance of notices of violation to the Company with respect to the Company's Plant Watson. The case against Alabama Power (including claims involving a unit co-owned by the Company) has been actively litigated in the U.S. District Court for the Northern District of Alabama, resulting in a settlement in 2006 of the alleged NSR violations at Plant Miller; voluntary dismissal of certain claims by the EPA; and a grant of summary judgment for Alabama Power on all remaining claims and dismissal of the case with prejudice in 2011. In September 2013, the U.S. Court of Appeals for the Eleventh Circuit affirmed in part and reversed in part the 2011 judgment in favor of Alabama Power, and the case has been transferred back to the U.S. District Court for the Northern District of Alabama for further proceedings. | ||||||||||||
The Company believes it complied with applicable laws and regulations in effect at the time the work in question took place. The Clean Air Act authorizes maximum civil penalties of $25,000 to $37,500 per day, per violation, depending on the date of the alleged violation. An adverse outcome could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties. Such expenditures could affect future results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Environmental Remediation | ||||||||||||
The Company must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Company may also incur substantial costs to clean up properties. The Company has authority from the Mississippi PSC to recover approved environmental compliance costs through regulatory mechanisms. | ||||||||||||
In 2003, the Company and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as potentially responsible parties at a site that was owned by an electric transformer company that handled the Company's transformers. The TCEQ approved the final site remediation plan in December 2013 and, on March 28, 2014, the impacted utilities, including the Company, agreed to commence remediation actions on the site. The Company's environmental remediation liability is $0.5 million as of December 31, 2014 and is expected to be recovered through the ECO Plan. | ||||||||||||
The final outcome of this matter cannot now be determined. However, based on the currently known conditions at this site and the nature and extent of activities relating to this site, the Company does not believe that additional liabilities, if any, at this site would be material to the financial statements. | ||||||||||||
FERC Matters | ||||||||||||
In 2012, the Company entered into a settlement agreement with its wholesale customers with respect to the Company's request for revised rates under the wholesale cost-based electric tariff. The settlement agreement provided that base rates under the cost-based electric tariff increase by approximately $22.6 million over a 12-month period with revised rates effective April 1, 2012. A significant portion of the difference between the requested base rate increase and the agreed upon rate increase was due to a change in the recovery methodology for the return on the Kemper IGCC CWIP. Under the settlement agreement, a portion of CWIP will continue to accrue AFUDC. The tariff customers specifically agreed to the same regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking by the Mississippi PSC with respect to (i) the accounting for Kemper IGCC-related costs that cannot be capitalized, (ii) the accounting for the lease termination and purchase of Plant Daniel Units 3 and 4, and (iii) the establishment of a regulatory asset for certain potential plant retirement costs. | ||||||||||||
Also in 2012, the FERC approved a motion to place interim rates into effect beginning in May 2012. Later in 2012, the Company, with its wholesale customers, filed a final settlement agreement with the FERC. In May 2013, the Company received an order from the FERC accepting the settlement agreement. | ||||||||||||
In April 2013, the Company reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the MRA cost-based electric tariff, which was accepted by the FERC in May 2013. The 2013 settlement agreement provided that base rates under the MRA cost-based electric tariff will increase by approximately $24.2 million annually, effective April 1, 2013. | ||||||||||||
On March 31, 2014, the Company reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the MRA cost-based electric tariff. The settlement agreement, accepted by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised rates effective for services rendered beginning May 1, 2014. | ||||||||||||
Retail Regulatory Matters | ||||||||||||
General | ||||||||||||
In 2012, the Mississippi PSC issued an order for the purpose of investigating and reviewing, for informational purposes only, the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. In March 2013, the MPUS filed with the Mississippi PSC its report on the ROE formulas used by the Company and all other regulated electric utilities in Mississippi. The ultimate outcome of this matter cannot be determined at this time. | ||||||||||||
Energy Efficiency | ||||||||||||
In July 2013, the Mississippi PSC approved an energy efficiency and conservation rule requiring electric and gas utilities in Mississippi serving more than 25,000 customers to implement energy efficiency programs and standards. Quick Start Plans, which include a portfolio of energy efficiency programs that are intended to provide benefits to a majority of customers, were required to be filed within six months of the order and will be in effect for two to three years. An annual report addressing the performance of all energy efficiency programs is required. | ||||||||||||
On June 3, 2014, the Mississippi PSC approved the Company's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On October 20, 2014, the Company filed a revised compliance filing, which proposed an increase of $6.7 million in retail revenues for the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014. | ||||||||||||
Performance Evaluation Plan | ||||||||||||
The Company’s retail base rates are set under the PEP, a rate plan approved by the Mississippi PSC. Two filings are made for each calendar year: the PEP projected filing, which is typically filed prior to the beginning of the year based on projected revenue requirement, and the PEP lookback filing, which is filed after the year and allows for review of the actual revenue requirement compared to the projected filing. PEP was designed with the objective to reduce the impact of rate changes on the customer and provide incentives for the Company to keep customer prices low and customer satisfaction and reliability high. PEP is a mechanism for rate adjustments based on three indicators: price, customer satisfaction, and service reliability. | ||||||||||||
In 2011, the Company submitted its annual PEP lookback filing for 2010, which recommended no surcharge or refund. Later in 2011, the Company received a letter from the MPUS disputing certain items in the 2010 PEP lookback filing. In 2012, the Mississippi PSC issued an order canceling the Company's PEP lookback filing for 2011. In May 2013, the MPUS contested the Company's PEP lookback filing for 2012, which indicated a refund due to customers of $4.7 million. Unresolved matters related to certain costs included in the 2010 PEP lookback filing, which are currently under review, also impact the 2012 PEP lookback filing. | ||||||||||||
In March 2013, the Mississippi PSC approved the projected PEP filing for 2013, which resulted in a rate increase of 1.9%, or $15.3 million, annually, effective March 19, 2013. The Company may be entitled to $3.3 million in additional revenues related to 2013 as a result of the late implementation of the 2013 PEP rate increase. | ||||||||||||
On March 18, 2014, the Company submitted its annual PEP lookback filing for 2013, which indicated no surcharge or refund. On March 31, 2014, the Mississippi PSC suspended the filing to allow more time for review. | ||||||||||||
On June 3, 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for the Company and other regulated electric utilities in Mississippi. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Environmental Compliance Overview Plan | ||||||||||||
In 2012, the Mississippi PSC approved the Company's request for a CPCN to construct scrubbers on Plant Daniel Units 1 and 2, which are scheduled to be placed in service in September and November 2015, respectively. These units are jointly owned by the Company and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with the Company's portion being $330 million, excluding AFUDC. The Company's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project. As of December 31, 2014, total project expenditures were $518.2 million, of which the Company's portion was $263.4 million, excluding AFUDC of $19.2 million. | ||||||||||||
In August 2013, the Mississippi PSC approved the Company’s 2013 ECO Plan filing which proposed no change in rates. | ||||||||||||
On August 1, 2014, the Company entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct scrubbers on Plant Daniel Units 1 and 2. In addition, and consistent with the Company's ongoing evaluation of recent environmental rules and regulations, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 28, 2014, the Chancery Court of Harrison County, Mississippi dismissed the Sierra Club's appeal related to the CPCN to construct scrubbers on Plant Daniel Units 1 and 2. | ||||||||||||
In accordance with a 2011 accounting order from the Mississippi PSC, the Company has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. This request was made to minimize the potential rate impact to customers arising from pending and final environmental regulations which may require the premature retirement of some generating units. As of December 31, 2014, $5.6 million of Plant Greene County costs and $2.0 million of costs related to Plant Watson have been reclassified as a regulatory asset. These costs are expected to be recovered through the ECO plan and other existing cost recovery mechanisms. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Watson and Greene County in 2015 and 2016, respectively. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on the Company's financial statements. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Fuel Cost Recovery | ||||||||||||
The Company establishes, annually, a retail fuel cost recovery factor that is approved by the Mississippi PSC. The Company is required to file for an adjustment to the retail fuel cost recovery factor annually; the most recent filing occurred on November 17, 2014. On January 13, 2015, the Mississippi PSC approved the 2015 retail fuel cost recovery factor, effective January 21, 2015. The retail fuel cost recovery factor will result in an annual increase of approximately $7.9 million. At December 31, 2014, the amount of under-recovered retail fuel costs included in the balance sheets was $2.5 million compared to a $14.5 million over-recovered balance at December 31, 2013. | ||||||||||||
The Company also has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. Effective January 1, 2015, the wholesale MRA fuel rate decreased resulting in an annual decrease of $1.1 million. Effective February 1, 2015, the wholesale MB fuel rate decreased, resulting in an annual decrease of $0.1 million. At December 31, 2014, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $0.2 million compared to an over-recovered balance of $7.3 million at December 31, 2013. At December 31, 2014, the amount of over-recovered wholesale MB fuel costs included in the balance sheets was immaterial compared to an over-recovered balance of $0.3 million at December 31, 2013. In addition, at December 31, 2014, the amount of over-recovered MRA emissions allowance cost included in the balance sheets was $0.3 million compared to a $3.8 million under-recovered balance at December 31, 2013. The Company's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on the Company's revenues or net income, but will affect cash flow. | ||||||||||||
Ad Valorem Tax Adjustment | ||||||||||||
The Company establishes, annually, an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by the Company. On May 6, 2014, the Mississippi PSC approved the Company's annual ad valorem tax adjustment factor filing for 2014, in which the Company requested an annual rate increase of 0.38%, or $3.6 million in annual retail revenues, primarily due to an increase in property tax rates. | ||||||||||||
Baseload Act | ||||||||||||
In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. In the 2015 Mississippi Supreme Court (Court) decision, the Court declined to rule on the constitutionality of the Baseload Act. See "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and " – 2015 Mississippi Supreme Court Decision" herein for additional information. | ||||||||||||
Integrated Coal Gasification Combined Cycle | ||||||||||||
Kemper IGCC Overview | ||||||||||||
Construction of the Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity of 582 MWs. The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. In connection with the Kemper IGCC, the Company constructed and plans to operate approximately 61 miles of CO2 pipeline infrastructure for the planned transport of captured CO2 for use in enhanced oil recovery. | ||||||||||||
Kemper IGCC Schedule and Cost Estimate | ||||||||||||
In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. | ||||||||||||
The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245.3 million of DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. | ||||||||||||
The Kemper IGCC was originally projected to be placed in service in May 2014. The Company placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service on natural gas on August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. | ||||||||||||
Recovery of the Kemper IGCC cost of the lignite mine and equipment, the cost of the CO2 pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when the Company demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) and costs subject to the cost cap remain subject to review and approval by the Mississippi PSC. The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court's decision), and actual costs incurred as of December 31, 2014, as adjusted for the Court's decision, are as follows: | ||||||||||||
Cost Category | 2010 Project Estimate(f) | Current Estimate | Actual Costs at 12/31/2014 | |||||||||
(in billions) | ||||||||||||
Plant Subject to Cost Cap(a) | $ | 2.4 | $ | 4.93 | $ | 4.23 | ||||||
Lignite Mine and Equipment | 0.21 | 0.23 | 0.23 | |||||||||
CO2 Pipeline Facilities | 0.14 | 0.11 | 0.1 | |||||||||
AFUDC(b)(c) | 0.17 | 0.63 | 0.45 | |||||||||
Combined Cycle and Related Assets Placed in | — | 0.02 | 0 | |||||||||
Service – Incremental(d) | ||||||||||||
General Exceptions | 0.05 | 0.1 | 0.07 | |||||||||
Deferred Costs(c)(e) | — | 0.18 | 0.12 | |||||||||
Total Kemper IGCC(a)(c) | $ | 2.97 | $ | 6.2 | $ | 5.2 | ||||||
(a) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014 that are subject to the $2.88 billion cost cap and excludes post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(b) | The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." | |||||||||||
(c) | Amounts in the Current Estimate reflect estimated costs through March 31, 2016. | |||||||||||
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||
(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC. | |||||||||||
Of the total costs, including post-in-service costs for the lignite mine, incurred as of December 31, 2014, $3.04 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $2.05 billion), $1.8 million in other property and investments, $44.7 million in fossil fuel stock, $32.5 million in materials and supplies, $147.7 million in other regulatory assets, $11.6 million in other deferred charges and assets, and $23.6 million in AROs in the balance sheet, with $1.1 million previously expensed. | ||||||||||||
The Company does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. The Company recorded pre-tax charges to income for revisions to the cost estimate of $868.0 million ($536.0 million after tax), $1.10 billion ($680.5 million after tax), and $78.0 million ($48.2 million after tax) in 2014, 2013 and 2012, respectively. The increases to the cost estimate in 2014 primarily reflected costs related to extension of the project's schedule to ensure the required time for start-up activities and operational readiness, completion of construction, additional resources during start-up, and ongoing construction support during start-up and commissioning activities. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $25 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities. Any further extension of the in-service date with respect to the Kemper IGCC would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $13 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees, which are being deferred as regulatory assets and are estimated to total approximately $7 million per month. | ||||||||||||
Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in the Company's statements of operations and these changes could be material. | ||||||||||||
Rate Recovery of Kemper IGCC Costs | ||||||||||||
See "FERC Matters" for additional information regarding the Company's MRA cost-based tariff relating to recovery of a portion of the Kemper IGCC costs from the Company's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note 3 under "Retail Regulatory Matters – Baseload Act" for additional information. See "Investment Tax Credits and Bonus Depreciation" and "Section 174 Research and Experimental Deduction" herein for additional tax information related to the Kemper IGCC. | ||||||||||||
The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on the Company's results of operations, financial condition, and liquidity. | ||||||||||||
2012 MPSC CPCN Order | ||||||||||||
The 2012 MPSC CPCN Order included provisions relating to both the Company's recovery of financing costs during the course of construction of the Kemper IGCC and the Company's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in the Company's petition for the CPCN. The Company expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the Rate Mitigation Plan (defined below) and other related proceedings during the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or the Company incurs additional costs to satisfy such parameters, there could be a material adverse impact on the Company's financial statements. | ||||||||||||
2013 Settlement Agreement | ||||||||||||
In January 2013, the Company entered into a settlement agreement with the Mississippi PSC that, among other things, established the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, the Company agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allowed the Company to secure alternate financing for costs not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. The Court found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. See "2015 Mississippi Supreme Court Decision" below for additional information. | ||||||||||||
Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in February 2013. The Company's intent under the 2013 Settlement Agreement was to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Rate Mitigation Plan as approved by the Mississippi PSC. | ||||||||||||
The Court's decision did not impact the Company's ability to utilize alternate financing through securitization, the 2012 MPSC CPCN Order, or the February 2013 legislation. See "2015 Mississippi Supreme Court Decision" below for additional information. | ||||||||||||
2013 MPSC Rate Order | ||||||||||||
Consistent with the terms of the 2013 Settlement Agreement, in March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014. For the period from March 2013 through December 31, 2014, $257.2 million had been collected primarily to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. | ||||||||||||
Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, the Company continues to record AFUDC on the Kemper IGCC through the in-service date. The Company will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. The Company will continue to record AFUDC and collect and defer the approved rates through the in-service date until directed to do otherwise by the Mississippi PSC. | ||||||||||||
On August 18, 2014, the Company provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. The Company's analysis requested, among other things, confirmation of the Company's accounting treatment by the Mississippi PSC of the continued collection of rates as prescribed by the 2013 MPSC Rate Order, with the current recognition as revenue of the related equity return on all assets placed in service and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account. See "2015 Mississippi Supreme Court Decision" for additional information regarding the decision of the Court which would discontinue the collection of, and require the refund of, all amounts previously collected under the 2013 MPSC Rate Order. | ||||||||||||
In addition, the Company's August 18, 2014 filing with the Mississippi PSC requested confirmation of the Company's accounting treatment by the Mississippi PSC of the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC and the deferral of operating costs for the combined cycle as regulatory assets. Under the Company's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" for additional information. Any action by the Mississippi PSC that is inconsistent with the treatment requested by the Company could have a material impact on the results of operations, financial condition, and liquidity of the Company. | ||||||||||||
2015 Mississippi Supreme Court Decision | ||||||||||||
On February 12, 2015, the Court issued its decision in the legal challenge to the 2013 MPSC Rate Order filed by Thomas A. Blanton. The Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. The Court's ruling remands the matter to the Mississippi PSC to (1) fix by order the rates that were in existence prior to the 2013 MPSC Rate Order, (2) fix no rate increases until the Mississippi PSC is in compliance with the Court's ruling, and (3) enter an order refunding amounts collected under the 2013 MPSC Rate Order. Through December 31, 2014, the Company had collected $257.2 million through rates under the 2013 MPSC Rate Order. Any required refunds would also include carrying costs. The Court's decision will become legally effective upon the issuance of a mandate to the Mississippi PSC. Absent specific instruction from the Court, the Mississippi PSC will determine the method and timing of the refund. The Company is reviewing the Court's decision and expects to file a motion for rehearing which would stay the Court's mandate until either the case is reheard and decided or seven days after the Court issues its order denying the Company's request for rehearing. The Company is also evaluating its regulatory options. | ||||||||||||
Rate Mitigation Plan | ||||||||||||
In March 2013, the Company, in compliance with the 2013 MPSC Rate Order, filed a revision to the proposed rate recovery plan with the Mississippi PSC for the Kemper IGCC for cost recovery through 2020 (Rate Mitigation Plan), which is still under review by the Mississippi PSC. The revenue requirements set forth in the Rate Mitigation Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation, which currently requires that the related long-term asset be placed in service in 2015. In the Rate Mitigation Plan, the Company proposed recovery of an annual revenue requirement of approximately $156 million of Kemper IGCC-related operational costs and rate base amounts, including plant costs equal to the $2.4 billion certificated cost estimate. The 2013 MPSC Rate Order, which increased rates beginning in March 2013, was integral to the Rate Mitigation Plan, which contemplates amortization of the regulatory liability balance at the in-service date to be used to mitigate customer rate impacts through 2020, based on a fixed amortization schedule that requires approval by the Mississippi PSC. Under the Rate Mitigation Plan, the Company proposed annual rate recovery to remain the same from 2014 through 2020, with the proposed revenue requirement approximating the forecasted cost of service for the period 2014 through 2020. Under the Company's proposal, to the extent the actual annual cost of service differs from the approved forecast for certain items, the difference would be deferred as a regulatory asset or liability, subject to accrual of carrying costs, and would be included in the next year's rate recovery calculation. If any deferred balance remains at the end of 2020, the Mississippi PSC would review the amount and, if approved, determine the appropriate method and period of disposition. See "Regulatory Assets and Liabilities" and "Investment Tax Credits and Bonus Depreciation" for additional information. | ||||||||||||
To the extent that refunds of amounts collected under the 2013 MPSC Rate Order are required on a schedule different from the amortization schedule proposed in the Rate Mitigation Plan, the customer billing impacts proposed under the Rate Mitigation Plan would no longer be viable. See "2015 Mississippi Supreme Court Decision" above for additional information. | ||||||||||||
In the event that the Mirror CWIP regulatory liability is refunded to customers prior to the in-service date of the Kemper IGCC and is, therefore, not available to mitigate rate impacts under the Rate Mitigation Plan, the Mississippi PSC does not approve a refund schedule that facilitates rate mitigation, or the Company withdraws the Rate Mitigation Plan, the Company would seek rate recovery through alternate means, which could include a traditional rate case. | ||||||||||||
In addition to current estimated costs at December 31, 2014 of $6.20 billion, the Company anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC. | ||||||||||||
Prudence Reviews | ||||||||||||
The Mississippi PSC's review of Kemper IGCC costs is ongoing. On August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the MPUS. The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and the Company is working to reach a mutually acceptable resolution. As a result of the Court's decision, the Company intends to request that the Mississippi PSC reconsider its prudence review schedule. See "2015 Mississippi Supreme Court Decision" for additional information. | ||||||||||||
Regulatory Assets and Liabilities | ||||||||||||
Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC issued an accounting order in 2011 granting the Company the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, carrying costs on Kemper IGCC assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service. | ||||||||||||
On August 18, 2014, the Company requested confirmation by the Mississippi PSC of the Company's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, the Company is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of December 31, 2014, the regulatory asset balance associated with the Kemper IGCC was $147.7 million. The projected balance at March 31, 2016 is estimated to total approximately $269.8 million. The amortization period of 40 years proposed by the Company for any such costs approved for recovery remains subject to approval by the Mississippi PSC. | ||||||||||||
The 2013 MPSC Rate Order approved retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014. On February 12, 2015, the Court ordered the Mississippi PSC to refund Mirror CWIP and to fix by order the rates that were in existence prior to the 2013 MPSC Rate Order. The Company is deferring the collections under the approved rates in the Mirror CWIP regulatory liability until otherwise directed by the Mississippi PSC. The Company is also accruing carrying costs on the unamortized balance of the Mirror CWIP regulatory liability for the benefit of retail customers. As of December 31, 2014, the balance of the Mirror CWIP regulatory liability, including carrying costs, was $270.8 million. | ||||||||||||
See "2015 Mississippi Supreme Court Decision" for additional information. | ||||||||||||
See Note 1 under "Regulatory Assets and Liabilities" for additional information. | ||||||||||||
Lignite Mine and CO2 Pipeline Facilities | ||||||||||||
In conjunction with the Kemper IGCC, the Company will own the lignite mine and equipment and has acquired and will continue to acquire mineral reserves located around the Kemper IGCC site. The mine started commercial operation in June 2013. | ||||||||||||
In 2010, the Company executed a 40-year management fee contract with Liberty Fuels Company, LLC (Liberty Fuels), a wholly-owned subsidiary of The North American Coal Corporation, which developed, constructed, and is operating and managing the mining operations. The contract with Liberty Fuels is effective through the end of the mine reclamation. As the mining permit holder, Liberty Fuels has a legal obligation to perform mine reclamation and the Company has a contractual obligation to fund all reclamation activities. In addition to the obligation to fund the reclamation activities, the Company currently provides working capital support to Liberty Fuels through cash advances for capital purchases, payroll, and other operating expenses. See Note 1 under "Asset Retirement Obligations and Other Costs of Removal" and "Variable Interest Entities" for additional information. | ||||||||||||
In addition, the Company has constructed and will operate the CO2 pipeline for the planned transport of captured CO2 for use in enhanced oil recovery. The Company has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO2 captured from the Kemper IGCC and Treetop will purchase 30% of the CO2 captured from the Kemper IGCC. The agreements with Denbury and Treetop provide termination rights in the event that the Company does not satisfy its contractual obligation with respect to deliveries of captured CO2 by May 11, 2015. While the Company has received no indication from either Denbury or Treetop of their intent to terminate their respective agreements, any termination could result in a material reduction in future chemical product sales revenues and could have a material financial impact on the Company to the extent the Company is not able to enter into other similar contractual arrangements. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Proposed Sale of Undivided Interest to SMEPA | ||||||||||||
In 2010, the Company and SMEPA entered into an APA whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, the Company and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, the Company and SMEPA signed an amendment to the APA whereby the Company and SMEPA agreed to amend the power supply agreement entered into by the parties in 2011 to reduce the capacity amounts to be received by SMEPA by half (approximately 75 MWs) at the sale and transfer of the undivided interest in the Kemper IGCC to SMEPA. Capacity revenues under the 2011 power supply agreement were $16.7 million in 2014. In December 2013, the Company and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014. | ||||||||||||
By letter agreement dated October 6, 2014, the Company and SMEPA agreed in principle on certain issues related to SMEPA's proposed purchase of a 15% undivided interest in the Kemper IGCC. The letter agreement contemplated certain amendments to the APA, which the parties anticipated to be incorporated into the APA on or before December 31, 2014. The parties agreed to further amend the APA as follows: (1) the Company agreed to cap at $2.88 billion the portion of the purchase price payable for development and construction costs, net of the Cost Cap Exceptions, title insurance reimbursement, and AFUDC and/or carrying costs through the Closing Commitment Date (defined below); (2) SMEPA agreed to close the purchase within 180 days after the date of the execution of the amended APA or before the Kemper IGCC in-service date, whichever occurs first (Closing Commitment Date), subject only to satisfaction of certain conditions; and (3) AFUDC and/or carrying costs will continue to be accrued on the capped development and construction costs, the Cost Cap Exceptions, and any operating costs, net of revenues until the amended APA is executed by both parties, and thereafter AFUDC and/or carrying costs and payment of interest on SMEPA's deposited money will be suspended and waived provided closing occurs by the Closing Commitment Date. The letter agreement also provided for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service. | ||||||||||||
By letter dated December 18, 2014, SMEPA notified the Company that SMEPA decided not to extend the estimated closing date in the APA or revise the APA to include the contemplated amendments; however, both parties agree that the APA will remain in effect until closing or until either party gives notice of termination. | ||||||||||||
The closing of this transaction is also conditioned upon execution of a joint ownership and operating agreement, the absence of material adverse effects, receipt of all construction permits, and appropriate regulatory approvals, as well as SMEPA's receipt of Rural Utilities Service (RUS) funding. In 2012, SMEPA received a conditional loan commitment from RUS for the purchase. | ||||||||||||
In 2012, on January 2, 2014, and on October 9, 2014, the Company received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the purchase. While the expectation is that these amounts will be applied to the purchase price at closing, the Company would be required to refund the deposits upon the termination of the APA or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposits and SMEPA's ability to request a refund, the deposits have been presented as a current liability in the balance sheet and as financing proceeds in the statement of cash flow. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of the Company with respect to any required refund of the deposits. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Investment Tax Credits and Bonus Depreciation | ||||||||||||
The IRS allocated $279.0 million (Phase II) of Internal Revenue Code Section 48A tax credits to the Company in connection with the Kemper IGCC. Through December 31, 2014, the Company had recorded tax benefits totaling $276.4 million for the Phase II credits, of which approximately $210.0 million had been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. The Company currently expects to place the Kemper IGCC in service in the first half of 2016. In addition, a portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's proposed purchase of an undivided interest in the Kemper IGCC as described above. | ||||||||||||
On December 19, 2014, the Tax Increase Prevention Act of 2014 (TIPA) was signed into law. The TIPA retroactively extended several tax credits through 2014 and extended 50% bonus depreciation for property placed in service in 2014 (and for certain long-term production-period projects to be placed in service in 2015). The extension of 50% bonus depreciation had a positive impact on the Company's cash flows and combined with bonus depreciation allowed in 2014 under the American Taxpayer Relief Act of 2012, resulted in approximately $130 million of positive cash flows related to the combined cycle and associated common facilities portion of the Kemper IGCC for the 2014 tax year. The estimated cash flow benefit of bonus depreciation related to TIPA is expected to be approximately $45 million to $50 million for the 2015 tax year. | ||||||||||||
The ultimate outcome of these matters cannot be determined at this time. | ||||||||||||
Section 174 Research and Experimental Deduction | ||||||||||||
Southern Company, on behalf of the Company, reduced tax payments for 2014 and included in its 2013 consolidated federal income tax return deductions for research and experimental (R&E) expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, the Company recorded an unrecognized tax benefit of approximately $160 million as of December 31, 2014. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||
Other Matters | ||||||||||||
Sierra Club Settlement Agreement | ||||||||||||
On August 1, 2014, the Company entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the scrubber project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw all appeals associated with certification of the Kemper IGCC and the Plant Daniel Units 1 and 2 scrubber project, which the applicable courts subsequently granted. | ||||||||||||
Under the Sierra Club Settlement Agreement, the Company agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, the Company paid $7 million in 2014, recognized in other income (expense), net in the statement of operations. In addition, and consistent with the Company's ongoing evaluation of recent environmental rules and regulations, the Company agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. The Company also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See Note 3 under "Retail Regulatory Matters – Environmental Compliance Overview Plan" for additional information. | ||||||||||||
Southern Power [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
CONTINGENCIES AND REGULATORY MATTERS | CONTINGENCIES AND REGULATORY MATTERS | |||||||||||
General Litigation Matters | ||||||||||||
The Company is subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Company's business activities are subject to extensive governmental regulation related to public health and the environment. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters. The ultimate outcome of such pending or potential litigation against the Company and its subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company's financial statements. |
Joint_Ownership_Agreements
Joint Ownership Agreements | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Joint Ownership Agreements [Line Items] | |||||||||||||||||||
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS | ||||||||||||||||||
Alabama Power owns an undivided interest in Units 1 and 2 at Plant Miller and related facilities jointly with PowerSouth Energy Cooperative, Inc. Georgia Power owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, the City of Dalton, Georgia, Florida Power & Light Company, and Jacksonville Electric Authority. In addition, Georgia Power has joint ownership agreements with OPC for the Rocky Mountain facilities and with Duke Energy Florida, Inc. for a combustion turbine unit at Intercession City, Florida. Southern Power owns an undivided interest in Plant Stanton Unit A and related facilities jointly with the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency. | |||||||||||||||||||
At December 31, 2014, Alabama Power's, Georgia Power's, and Southern Power's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows: | |||||||||||||||||||
Facility (Type) | Percent | Plant in Service | Accumulated | CWIP | |||||||||||||||
Ownership | Depreciation | ||||||||||||||||||
(in millions) | |||||||||||||||||||
Plant Vogtle (nuclear) Units 1 and 2 | 45.7 | % | $ | 3,420 | $ | 2,059 | $ | 46 | |||||||||||
Plant Hatch (nuclear) | 50.1 | 1,117 | 559 | 66 | |||||||||||||||
Plant Miller (coal) Units 1 and 2 | 91.8 | 1,512 | 561 | 14 | |||||||||||||||
Plant Scherer (coal) Units 1 and 2 | 8.4 | 254 | 83 | 1 | |||||||||||||||
Plant Wansley (coal) | 53.5 | 856 | 278 | 15 | |||||||||||||||
Rocky Mountain (pumped storage) | 25.4 | 182 | 124 | 2 | |||||||||||||||
Intercession City (combustion turbine) | 33.3 | 14 | 5 | — | |||||||||||||||
Plant Stanton (combined cycle) Unit A | 65 | 157 | 47 | — | |||||||||||||||
Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4 that are currently under construction. See Note 3 under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" for additional information. | |||||||||||||||||||
Alabama Power, Georgia Power, and Southern Power have contracted to operate and maintain the jointly-owned facilities, except for Rocky Mountain and Intercession City, as agents for their respective co-owners. The companies' proportionate share of their plant operating expenses is included in the corresponding operating expenses in the statements of income and each company is responsible for providing its own financing. | |||||||||||||||||||
Alabama Power [Member] | |||||||||||||||||||
Joint Ownership Agreements [Line Items] | |||||||||||||||||||
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS | ||||||||||||||||||
The Company and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Georgia Power under a power contract. The Company and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and ROE. The Company's share of purchased power totaled $84 million in 2014, $88 million in 2013, and $109 million in 2012 and is included in "Purchased power from affiliates" in the statements of income. The Company accounts for SEGCO using the equity method. | |||||||||||||||||||
In addition, the Company has guaranteed unconditionally the obligation of SEGCO under an installment sale agreement for the purchase of certain pollution control facilities at SEGCO's generating units, pursuant to which $25 million principal amount of pollution control revenue bonds are outstanding. The Company has guaranteed $100 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes. These senior notes mature on December 1, 2018. The Company had guaranteed $50 million principal amount of unsecured senior notes issued by SEGCO for general corporate purposes, which matured on May 15, 2013. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to its then proportionate ownership of stock of SEGCO if the Company is called upon to make such payment under its guarantee. | |||||||||||||||||||
At December 31, 2014, the capitalization of SEGCO consisted of $106 million of equity and $125 million of long-term debt on which the annual interest requirement is $3 million. In addition, SEGCO had short-term debt outstanding of $42 million. SEGCO paid dividends of $3 million in 2014, $7 million in 2013, and $14 million in 2012, of which one-half of each was paid to the Company. In addition, the Company recognizes 50% of SEGCO's net income. | |||||||||||||||||||
SEGCO plans to add natural gas as the primary fuel source for 1,000 MWs of its generating capacity in 2015. A natural gas pipeline was constructed and will be placed in service in 2015. The Company, which owns and operates a generating unit adjacent to the SEGCO generating units, has entered into a joint ownership agreement with SEGCO for the ownership of the gas pipeline. The Company will own 14% of the pipeline with the remaining 86% owned by SEGCO. At December 31, 2014, the Company's portion of the construction work in progress associated with the pipeline is $15 million. | |||||||||||||||||||
In addition to the Company's ownership of SEGCO and joint ownership of the natural gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2014 were as follows: | |||||||||||||||||||
Facility | Total MW Capacity | Company Ownership | Plant in Service | Accumulated Depreciation | Construction Work in Progress | ||||||||||||||
(in millions) | |||||||||||||||||||
Greene County | 500 | 60 | % | (1) | $ | 164 | $ | 96 | $ | 1 | |||||||||
Plant Miller | |||||||||||||||||||
Units 1 and 2 | 1,320 | 91.84 | % | (2) | 1,512 | 561 | 14 | ||||||||||||
-1 | Jointly owned with an affiliate, Mississippi Power. | ||||||||||||||||||
-2 | Jointly owned with PowerSouth Energy Cooperative, Inc. | ||||||||||||||||||
The Company has contracted to operate and maintain the jointly-owned facilities as agent for their co-owners. The Company's proportionate share of its plant operating expenses is included in operating expenses in the statements of income and the Company is responsible for providing its own financing. | |||||||||||||||||||
Georgia Power [Member] | |||||||||||||||||||
Joint Ownership Agreements [Line Items] | |||||||||||||||||||
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS | ||||||||||||||||||
The Company and Alabama Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. The capacity of these units is sold equally to the Company and Alabama Power under a power contract. The Company and Alabama Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and a ROE. The Company's share of purchased power totaled $84 million in 2014, $91 million in 2013, and $107 million in 2012 and is included in purchased power, affiliates in the statements of income. The Company accounts for SEGCO using the equity method. | |||||||||||||||||||
The Company owns undivided interests in Plants Vogtle, Hatch, Wansley, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, Florida Power & Light Company, Jacksonville Electric Authority, and Gulf Power. Under these agreements, the Company has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants. In addition, the Company jointly owns the Rocky Mountain pumped storage hydroelectric plant with OPC who is the operator of the plant. The Company and Duke Energy Florida, Inc. jointly own a combustion turbine unit (Intercession City) operated by Duke Energy Florida, Inc. | |||||||||||||||||||
At December 31, 2014, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows: | |||||||||||||||||||
Facility (Type) | Company Ownership | Plant in Service | Accumulated Depreciation | CWIP | |||||||||||||||
(in millions) | |||||||||||||||||||
Plant Vogtle (nuclear) | |||||||||||||||||||
Units 1 and 2 | 45.70% | $ | 3,420 | $ | 2,059 | $ | 46 | ||||||||||||
Plant Hatch (nuclear) | 50.1 | 1,117 | 559 | 66 | |||||||||||||||
Plant Wansley (coal) | 53.5 | 856 | 278 | 15 | |||||||||||||||
Plant Scherer (coal) | |||||||||||||||||||
Units 1 and 2 | 8.4 | 254 | 83 | 1 | |||||||||||||||
Unit 3 | 75 | 1,172 | 417 | 10 | |||||||||||||||
Rocky Mountain (pumped storage) | 25.4 | 182 | 124 | 2 | |||||||||||||||
Intercession City (combustion-turbine) | 33.3 | 14 | 5 | — | |||||||||||||||
The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing. | |||||||||||||||||||
The Company also owns 45.7% of Plant Vogtle Units 3 and 4 that are currently under construction. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information. | |||||||||||||||||||
Gulf Power [Member] | |||||||||||||||||||
Joint Ownership Agreements [Line Items] | |||||||||||||||||||
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS | ||||||||||||||||||
The Company and Mississippi Power jointly own Plant Daniel Units 1 and 2, which together represent capacity of 1,000 MWs. Plant Daniel is a generating plant located in Jackson County, Mississippi. In accordance with the operating agreement, Mississippi Power acts as the Company's agent with respect to the construction, operation, and maintenance of these units. | |||||||||||||||||||
The Company and Georgia Power jointly own the 818 MWs capacity Plant Scherer Unit 3. Plant Scherer is a generating plant located near Forsyth, Georgia. In accordance with the operating agreement, Georgia Power acts as the Company's agent with respect to the construction, operation, and maintenance of the unit. | |||||||||||||||||||
At December 31, 2014, the Company's percentage ownership and investment in these jointly-owned facilities were as follows: | |||||||||||||||||||
Plant Scherer | Plant Daniel Units 1 & 2 (coal) | ||||||||||||||||||
Unit 3 (coal) | |||||||||||||||||||
(in thousands) | |||||||||||||||||||
Plant in service | $ | 387,511 | (a) | $ | 285,834 | ||||||||||||||
Accumulated depreciation | 130,069 | 177,304 | |||||||||||||||||
Construction work in progress | 2,912 | 286,343 | |||||||||||||||||
Company Ownership | 25 | % | 50 | % | |||||||||||||||
(a) | Includes net plant acquisition adjustment of $1.8 million. | ||||||||||||||||||
The Company's proportionate share of its plant operating expenses is included in the corresponding operating expenses in the statements of income and the Company is responsible for providing its own financing. | |||||||||||||||||||
Mississippi Power [Member] | |||||||||||||||||||
Joint Ownership Agreements [Line Items] | |||||||||||||||||||
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS | ||||||||||||||||||
The Company and Alabama Power own, as tenants in common, Units 1 and 2 (total capacity of 500 MWs) at Greene County Steam Plant, which is located in Alabama and operated by Alabama Power. Additionally, the Company and Gulf Power, own as tenants in common, Units 1 and 2 (total capacity of 1,000 MWs) at Plant Daniel, which is located in Mississippi and operated by the Company. | |||||||||||||||||||
In August 2014, a decision was made to cease coal operations at Greene County Steam Plant and convert to natural gas no later than April 16, 2016. As a result, active construction projects related to these assets were cancelled in September 2014. Associated amounts in CWIP of $5.6 million, reflecting the Company's share of the costs, were subsequently transferred to regulatory assets. See Note 3 under "Retail Regulatory Matters-Environmental Compliance Overview Plan" herein for additional information. | |||||||||||||||||||
At December 31, 2014, the Company's percentage ownership and investment in these jointly-owned facilities in commercial operation were as follows: | |||||||||||||||||||
Generating | Company | Plant in Service | Accumulated | CWIP | |||||||||||||||
Plant | Ownership | Depreciation | |||||||||||||||||
(in thousands) | |||||||||||||||||||
Greene County | |||||||||||||||||||
Units 1 and 2 | 40 | % | $ | 102,384 | $ | 51,911 | $ | 902 | |||||||||||
Daniel | |||||||||||||||||||
Units 1 and 2 | 50 | % | $ | 299,440 | $ | 155,606 | $ | 286,240 | |||||||||||
The Company's proportionate share of plant operating expenses is included in the statements of operations and the Company is responsible for providing its own financing. | |||||||||||||||||||
See Note 3 under "Retail Regulatory Matters – Environmental Compliance Overview Plan" for additional information. | |||||||||||||||||||
Southern Power [Member] | |||||||||||||||||||
Joint Ownership Agreements [Line Items] | |||||||||||||||||||
JOINT OWNERSHIP AGREEMENTS | JOINT OWNERSHIP AGREEMENTS | ||||||||||||||||||
The Company is a 65% owner of Plant Stanton A, a combined-cycle project unit with a nameplate capacity of 659 MWs. The unit is co-owned by the Orlando Utilities Commission (28%), Florida Municipal Power Agency (3.5%), and Kissimmee Utility Authority (3.5%). The Company has a service agreement with SCS whereby SCS is responsible for the operation and maintenance of Plant Stanton A. As of December 31, 2014, $156.5 million was recorded in plant in service with associated accumulated depreciation of $46.6 million. These amounts represent the Company's share of the total plant assets and each owner is responsible for providing its own financing. The Company's proportionate share of Plant Stanton A's operating expense is included in the corresponding operating expenses in the statements of income. |
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
INCOME TAXES | INCOME TAXES | |||||||||||
Southern Company files a consolidated federal income tax return, combined state income tax returns for the States of Alabama, Georgia, and Mississippi, and unitary income tax returns for the States of California, North Carolina, and Texas. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. | ||||||||||||
Current and Deferred Income Taxes | ||||||||||||
Details of income tax provisions are as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal — | ||||||||||||
Current | $ | 175 | $ | 363 | $ | 177 | ||||||
Deferred | 695 | 386 | 1,011 | |||||||||
870 | 749 | 1,188 | ||||||||||
State — | ||||||||||||
Current | 93 | (10 | ) | 61 | ||||||||
Deferred | 14 | 110 | 85 | |||||||||
107 | 100 | 146 | ||||||||||
Total | $ | 977 | $ | 849 | $ | 1,334 | ||||||
Net cash payments for income taxes in 2014, 2013, and 2012 were $272 million, $139 million, and $38 million, respectively. | ||||||||||||
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | ||||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation | $ | 11,125 | $ | 9,710 | ||||||||
Property basis differences | 1,332 | 1,515 | ||||||||||
Leveraged lease basis differences | 299 | 287 | ||||||||||
Employee benefit obligations | 613 | 491 | ||||||||||
Premium on reacquired debt | 103 | 113 | ||||||||||
Regulatory assets associated with employee benefit obligations | 1,390 | 705 | ||||||||||
Regulatory assets associated with AROs | 871 | 824 | ||||||||||
Other | 523 | 350 | ||||||||||
Total | 16,256 | 13,995 | ||||||||||
Deferred tax assets — | ||||||||||||
Federal effect of state deferred taxes | 430 | 421 | ||||||||||
Employee benefit obligations | 1,675 | 1,048 | ||||||||||
Over recovered fuel clause | — | 30 | ||||||||||
Other property basis differences | 453 | 157 | ||||||||||
Deferred costs | 86 | 84 | ||||||||||
ITC carryforward | 480 | 121 | ||||||||||
Unbilled revenue | 67 | 116 | ||||||||||
Other comprehensive losses | 89 | 54 | ||||||||||
AROs | 871 | 824 | ||||||||||
Estimated Loss on Kemper IGCC | 631 | 472 | ||||||||||
Deferred state tax assets | 117 | 77 | ||||||||||
Other | 342 | 220 | ||||||||||
Total | 5,241 | 3,624 | ||||||||||
Valuation allowance | (49 | ) | (49 | ) | ||||||||
Total deferred tax assets | 5,192 | 3,575 | ||||||||||
Total deferred tax liabilities, net | 11,064 | 10,420 | ||||||||||
Portion included in current assets/(liabilities), net | 504 | 143 | ||||||||||
Accumulated deferred income taxes | $ | 11,568 | $ | 10,563 | ||||||||
The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation. | ||||||||||||
At December 31, 2014, Southern Company had subsidiaries with State of Georgia net operating loss (NOL) carryforwards totaling $701 million, which could result in net state income tax benefits of $41 million, if utilized. However, the subsidiaries have established a valuation allowance for the entire amount due to the remote likelihood that the tax benefit will be realized. These NOLs expire between 2018 and 2021. Beginning in 2002, the State of Georgia allowed Southern Company to file a combined return, which has prevented the creation of any additional NOL carryforwards. | ||||||||||||
At December 31, 2014, the tax-related regulatory assets to be recovered from customers were $1.5 billion. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. | ||||||||||||
At December 31, 2014, the tax-related regulatory liabilities to be credited to customers were $192 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. | ||||||||||||
In accordance with regulatory requirements, deferred federal ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2014, $16 million in 2013, and $23 million in 2012. At December 31, 2014, Southern Company had a federal ITC carryforward which is expected to result in $379 million of federal income tax benefit. The ITC carryforward expires in 2023, but is expected to be utilized in 2015. Additionally, Southern Company had state ITC carryforwards for the states of Georgia and Mississippi totaling $159 million, which will expire between 2020 and 2024. | ||||||||||||
Effective Tax Rate | ||||||||||||
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | ||||||
State income tax, net of federal deduction | 2.3 | 2.5 | 2.5 | |||||||||
Employee stock plans dividend deduction | (1.4 | ) | (1.6 | ) | (1.0 | ) | ||||||
Non-deductible book depreciation | 1.4 | 1.5 | 0.9 | |||||||||
AFUDC-Equity | (2.9 | ) | (2.6 | ) | (1.3 | ) | ||||||
ITC basis difference | (1.6 | ) | (1.2 | ) | (0.3 | ) | ||||||
Other | (0.3 | ) | (0.5 | ) | (0.2 | ) | ||||||
Effective income tax rate | 32.5 | % | 33.1 | % | 35.6 | % | ||||||
Southern Company's effective tax rate is typically lower than the statutory rate due to its employee stock plans' dividend deduction and non-taxable AFUDC equity. The 2014 effective tax rate decrease, as compared to 2013, is primarily due to an increase in non-taxable AFUDC equity and an increase in tax benefits related to federal ITCs. Additionally, the 2013 effective rate decrease, as compared to 2012, is primarily due to an increase in non-taxable AFUDC equity. | ||||||||||||
Unrecognized Tax Benefits | ||||||||||||
Changes during the year in unrecognized tax benefits were as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 7 | $ | 70 | $ | 120 | ||||||
Tax positions increase from current periods | 64 | 3 | 13 | |||||||||
Tax positions increase from prior periods | 102 | — | 7 | |||||||||
Tax positions decrease from prior periods | (3 | ) | (66 | ) | (56 | ) | ||||||
Reductions due to settlements | — | — | (10 | ) | ||||||||
Reductions due to expired statute of limitations | — | — | (4 | ) | ||||||||
Balance at end of year | $ | 170 | $ | 7 | $ | 70 | ||||||
The tax positions increase from current periods and increase from prior periods for 2014 relate primarily to a deduction for R&E expenditures related to the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle – Section 174 Research and Experimental Deduction" for more information. The tax positions decrease from prior periods for 2013 relate primarily to the tax accounting method change for repairs related to generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. | ||||||||||||
The impact on Southern Company's effective tax rate, if recognized, is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Tax positions impacting the effective tax rate | $ | 10 | $ | 7 | $ | 5 | ||||||
Tax positions not impacting the effective tax rate | 160 | — | 65 | |||||||||
Balance of unrecognized tax benefits | $ | 170 | $ | 7 | $ | 70 | ||||||
The tax positions impacting the effective tax rate for 2014, 2013, and 2012 relate to federal and state income tax credits. The tax positions not impacting the effective tax rate for 2014 relate to a deduction for R&E expenditures related to the Kemper IGCC. The tax positions not impacting the effective tax rate for 2012 relate to the tax accounting method change for repairs related to generation assets. These amounts are presented on a gross basis without considering the related federal or state income tax impact. | ||||||||||||
Southern Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. Southern Company did not accrue any penalties on uncertain tax positions. | ||||||||||||
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. | ||||||||||||
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2008. | ||||||||||||
Tax Method of Accounting for Repairs | ||||||||||||
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company's financial statements. | ||||||||||||
Alabama Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
INCOME TAXES | INCOME TAXES | |||||||||||
On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files a separate company income tax return for the State of Tennessee. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. | ||||||||||||
Current and Deferred Income Taxes | ||||||||||||
Details of income tax provisions are as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal — | ||||||||||||
Current | $ | 198 | $ | 243 | $ | 262 | ||||||
Deferred | 225 | 160 | 137 | |||||||||
423 | 403 | 399 | ||||||||||
State — | ||||||||||||
Current | 44 | 36 | 51 | |||||||||
Deferred | 45 | 39 | 27 | |||||||||
89 | 75 | 78 | ||||||||||
Total | $ | 512 | $ | 478 | $ | 477 | ||||||
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | ||||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation | $ | 3,429 | $ | 3,187 | ||||||||
Property basis differences | 457 | 458 | ||||||||||
Premium on reacquired debt | 30 | 33 | ||||||||||
Employee benefit obligations | 215 | 209 | ||||||||||
Regulatory assets associated with employee benefit obligations | 366 | 198 | ||||||||||
Asset retirement obligations | 59 | 38 | ||||||||||
Regulatory assets associated with asset retirement obligations | 285 | 265 | ||||||||||
Other | 156 | 128 | ||||||||||
Total | 4,997 | 4,516 | ||||||||||
Deferred tax assets — | ||||||||||||
Federal effect of state deferred taxes | 219 | 205 | ||||||||||
Unbilled fuel revenue | 42 | 41 | ||||||||||
Storm reserve | 27 | 32 | ||||||||||
Employee benefit obligations | 400 | 231 | ||||||||||
Other comprehensive losses | 19 | 18 | ||||||||||
Asset retirement obligations | 344 | 303 | ||||||||||
Other | 90 | 108 | ||||||||||
Total | 1,141 | 938 | ||||||||||
Total deferred tax liabilities, net | 3,856 | 3,578 | ||||||||||
Portion included in current assets/(liabilities), net | 18 | 25 | ||||||||||
Accumulated deferred income taxes | $ | 3,874 | $ | 3,603 | ||||||||
The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation. | ||||||||||||
At December 31, 2014, the tax-related regulatory assets to be recovered from customers were $526 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. | ||||||||||||
At December 31, 2014, the tax-related regulatory liabilities to be credited to customers were $72 million. These liabilities are primarily attributable to unamortized ITCs. | ||||||||||||
In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $8 million in 2014, 2013 and 2012. At December 31, 2014, all ITCs available to reduce federal income taxes payable had been utilized. | ||||||||||||
Effective Tax Rate | ||||||||||||
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |||||||||
State income tax, net of federal deduction | 4.4 | 4 | 4.1 | |||||||||
Non-deductible book depreciation | 1.1 | 1 | 0.9 | |||||||||
Differences in prior years' deferred and current tax rates | -0.1 | -0.1 | -0.1 | |||||||||
AFUDC equity | -1.3 | -0.9 | -0.5 | |||||||||
Other | -0.1 | -0.1 | -0.3 | |||||||||
Effective income tax rate | 39.00% | 38.90% | 39.10% | |||||||||
Unrecognized Tax Benefits | ||||||||||||
The Company had no unrecognized tax benefits during 2014. Changes in unrecognized tax benefits in prior years were as follows: | ||||||||||||
2013 | 2012 | |||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 31 | $ | 32 | ||||||||
Tax positions from current periods | — | 5 | ||||||||||
Tax positions from prior periods | (31 | ) | (4 | ) | ||||||||
Reductions due to settlements | — | (2 | ) | |||||||||
Balance at end of year | $ | — | $ | 31 | ||||||||
The decrease in tax positions from prior periods for 2013 relates primarily to the tax accounting method change for repairs-generation assets, which did not impact the effective tax rate. See "Tax Method of Accounting for Repairs" herein for additional information. | ||||||||||||
These amounts are presented on a gross basis without considering the related federal or state income tax impact. The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions. | ||||||||||||
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2010. | ||||||||||||
Tax Method of Accounting for Repairs | ||||||||||||
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company's financial statements. | ||||||||||||
Georgia Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
INCOME TAXES | INCOME TAXES | |||||||||||
On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. | ||||||||||||
Current and Deferred Income Taxes | ||||||||||||
Details of income tax provisions are as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal – | ||||||||||||
Current | $ | 295 | $ | 277 | $ | 273 | ||||||
Deferred | 366 | 374 | 370 | |||||||||
661 | 651 | 643 | ||||||||||
State – | ||||||||||||
Current | 82 | (30 | ) | 38 | ||||||||
Deferred | (14 | ) | 102 | 7 | ||||||||
68 | 72 | 45 | ||||||||||
Total | $ | 729 | $ | 723 | $ | 688 | ||||||
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | ||||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities – | ||||||||||||
Accelerated depreciation | $ | 4,732 | $ | 4,479 | ||||||||
Property basis differences | 811 | 873 | ||||||||||
Employee benefit obligations | 329 | 232 | ||||||||||
Under-recovered fuel costs | 81 | — | ||||||||||
Premium on reacquired debt | 66 | 73 | ||||||||||
Regulatory assets associated with employee benefit obligations | 534 | 276 | ||||||||||
Asset retirement obligations | 497 | 495 | ||||||||||
Other | 160 | 168 | ||||||||||
Total | 7,210 | 6,596 | ||||||||||
Deferred tax assets – | ||||||||||||
Federal effect of state deferred taxes | 148 | 159 | ||||||||||
Employee benefit obligations | 642 | 388 | ||||||||||
Other property basis differences | 86 | 93 | ||||||||||
Other deferred costs | 86 | 84 | ||||||||||
Cost of removal obligations | 11 | 17 | ||||||||||
State tax credit carry forward | 170 | 118 | ||||||||||
Federal tax credit carry forward | 5 | 3 | ||||||||||
Over-recovered fuel costs | — | 22 | ||||||||||
Unbilled fuel revenue | 46 | 53 | ||||||||||
Asset retirement obligations | 497 | 495 | ||||||||||
Other | 46 | 32 | ||||||||||
Total | 1,737 | 1,464 | ||||||||||
Total deferred tax liabilities, net | 5,473 | 5,132 | ||||||||||
Portion included in current assets/(liabilities), net | 34 | 68 | ||||||||||
Accumulated deferred income taxes | $ | 5,507 | $ | 5,200 | ||||||||
The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation. | ||||||||||||
At December 31, 2014, tax-related regulatory assets to be recovered from customers were $702 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. | ||||||||||||
At December 31, 2014, tax-related regulatory liabilities to be credited to customers were $106 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. In 2011, the Company recorded a regulatory liability of $62 million related to a settlement with the Georgia Department of Revenue resolving claims for certain tax credits in 2005 through 2009. Amortization of the regulatory liability occurred ratably over the period from April 2012 through December 2013. | ||||||||||||
In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $10 million in 2014, $5 million in 2013, and $13 million in 2012. State ITCs are recognized in the period in which the credits are claimed on the state income tax return and totaled $34 million in 2014, $27 million in 2013, and $36 million in 2012. At December 31, 2014, the Company had $5 million in federal tax credit carry forwards that will expire by 2034 and $152 million in state ITC carry forwards that will expire between 2021 and 2025. | ||||||||||||
Effective Tax Rate | ||||||||||||
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |||||||||
State income tax, net of federal deduction | 2.2 | 2.5 | 1.6 | |||||||||
Non-deductible book depreciation | 1.3 | 1.3 | 1.2 | |||||||||
AFUDC equity | -0.8 | -0.6 | -1 | |||||||||
Other | -0.7 | -0.4 | -0.1 | |||||||||
Effective income tax rate | 37.00% | 37.80% | 36.70% | |||||||||
The decrease in the Company's 2014 effective tax rate is primarily the result of benefits related to emission allowances and state apportionment. The increase in the Company's 2013 effective tax rate is primarily the result of a decrease in state income tax credits and non-taxable AFUDC equity. | ||||||||||||
Unrecognized Tax Benefits | ||||||||||||
The Company had no unrecognized tax benefits during 2014. Changes in unrecognized tax benefits in prior years were as follows: | ||||||||||||
2013 | 2012 | |||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 23 | $ | 47 | ||||||||
Tax positions increase from current periods | — | 3 | ||||||||||
Tax positions increase from prior periods | — | 3 | ||||||||||
Tax positions decrease from prior periods | (23 | ) | (19 | ) | ||||||||
Reductions due to settlements | — | (8 | ) | |||||||||
Reductions due to expired statute of limitations | — | (3 | ) | |||||||||
Balance at end of year | $ | — | $ | 23 | ||||||||
The tax positions decrease from prior periods for 2013 and 2012 relate primarily to the tax accounting method change for repairs-generation assets and did not impact the effective tax rate. See "Tax Method of Accounting for Repairs" herein for additional information. | ||||||||||||
These amounts are presented on a gross basis without considering the related federal or state income tax impact. | ||||||||||||
The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions. | ||||||||||||
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2008. | ||||||||||||
Tax Method of Accounting for Repairs | ||||||||||||
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company's financial statements. | ||||||||||||
Gulf Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
INCOME TAXES | INCOME TAXES | |||||||||||
On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files a separate company income tax return for the State of Florida. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. | ||||||||||||
Current and Deferred Income Taxes | ||||||||||||
Details of income tax provisions are as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Federal - | ||||||||||||
Current | $ | 22,771 | $ | 5,009 | $ | (92,610 | ) | |||||
Deferred | 52,602 | 63,134 | 161,096 | |||||||||
75,373 | 68,143 | 68,486 | ||||||||||
State - | ||||||||||||
Current | (39 | ) | (2,410 | ) | (2,484 | ) | ||||||
Deferred | 12,728 | 13,935 | 13,209 | |||||||||
12,689 | 11,525 | 10,725 | ||||||||||
Total | $ | 88,062 | $ | 79,668 | $ | 79,211 | ||||||
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax liabilities- | ||||||||||||
Accelerated depreciation | $ | 776,953 | $ | 721,087 | ||||||||
Property basis differences | 52,242 | 45,960 | ||||||||||
Fuel recovery clause | 16,148 | 7,972 | ||||||||||
Pension and other employee benefits | 34,405 | 25,800 | ||||||||||
Regulatory assets associated with employee benefit obligations | 59,788 | 27,660 | ||||||||||
Regulatory assets associated with asset retirement obligations | 6,768 | 6,554 | ||||||||||
Other | 21,712 | 23,947 | ||||||||||
Total | 968,016 | 858,980 | ||||||||||
Deferred tax assets- | ||||||||||||
Federal effect of state deferred taxes | 30,587 | 24,277 | ||||||||||
Postretirement benefits | 18,033 | 17,816 | ||||||||||
Pension and other employee benefits | 65,506 | 33,015 | ||||||||||
Property reserve | 13,440 | 15,144 | ||||||||||
Asset retirement obligations | 6,768 | 6,554 | ||||||||||
Alternative minimum tax carryforward | 18,200 | 18,420 | ||||||||||
Other | 18,893 | 17,780 | ||||||||||
Total | 171,427 | 133,006 | ||||||||||
Net deferred tax liabilities | 796,589 | 725,974 | ||||||||||
Portion included in current assets/(liabilities), net | 3,134 | 8,381 | ||||||||||
Accumulated deferred income taxes | $ | 799,723 | $ | 734,355 | ||||||||
The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation. | ||||||||||||
At December 31, 2014, tax-related regulatory assets to be recovered from customers were $56.3 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. | ||||||||||||
At December 31, 2014, the tax-related regulatory liabilities to be credited to customers were $3.9 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. | ||||||||||||
In accordance with regulatory requirements, deferred federal ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $1.3 million in 2014 and $1.4 million in both 2013 and 2012. At December 31, 2014, all ITCs available to reduce federal income taxes payable had been utilized. | ||||||||||||
Effective Tax Rate | ||||||||||||
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |||||||||
State income tax, net of federal deduction | 3.5 | 3.5 | 3.3 | |||||||||
Non-deductible book depreciation | 0.4 | 0.5 | 0.5 | |||||||||
Differences in prior years' deferred and current tax rates | -0.1 | -0.2 | -0.2 | |||||||||
AFUDC equity | -1.8 | -1.1 | -0.9 | |||||||||
Other, net | 0.1 | -0.1 | -0.2 | |||||||||
Effective income tax rate | 37.10% | 37.60% | 37.50% | |||||||||
The decrease in the Company's 2014 effective tax rate is primarily the result of an increase in AFUDC equity which is not taxable. | ||||||||||||
Unrecognized Tax Benefits | ||||||||||||
Changes during the year in unrecognized tax benefits were as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 45 | $ | 5,007 | $ | 2,892 | ||||||
Tax positions increase from current periods | 46 | 45 | 2,630 | |||||||||
Tax positions increase/(decrease) from prior periods | (45 | ) | (5,007 | ) | 515 | |||||||
Reductions due to settlements | — | — | (1,030 | ) | ||||||||
Balance at end of year | $ | 46 | $ | 45 | $ | 5,007 | ||||||
The tax positions increase from current periods and decrease from prior periods for 2014 relate primarily to the research and development credit. The tax positions decrease from prior periods for 2013 relate primarily to the tax accounting method change for repairs related to generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. | ||||||||||||
The impact on the Company's effective tax rate, if recognized, is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Tax positions impacting the effective tax rate | $ | 46 | $ | 45 | $ | 45 | ||||||
Tax positions not impacting the effective tax rate | — | — | 4,962 | |||||||||
Balance of unrecognized tax benefits | $ | 46 | $ | 45 | $ | 5,007 | ||||||
The tax positions impacting the effective tax rate for all periods presented relate primarily to the research and development credit. The tax positions not impacting the effective tax rate for 2012 relate to the tax accounting method change for repairs related to generation assets. These amounts are presented on a gross basis without considering the related federal or state income tax impact. | ||||||||||||
The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions. | ||||||||||||
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. | ||||||||||||
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2010. | ||||||||||||
Tax Method of Accounting for Repairs | ||||||||||||
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company's financial statements. | ||||||||||||
Mississippi Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
INCOME TAXES | INCOME TAXES | |||||||||||
On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama and Mississippi. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. | ||||||||||||
Current and Deferred Income Taxes | ||||||||||||
Details of income tax provisions are as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Federal — | ||||||||||||
Current | $ | (431,077 | ) | $ | 23,345 | $ | 1,212 | |||||
Deferred | 183,461 | (342,870 | ) | 16,994 | ||||||||
(247,616 | ) | (319,525 | ) | 18,206 | ||||||||
State — | ||||||||||||
Current | 455 | 5,219 | 1,656 | |||||||||
Deferred | (38,044 | ) | (53,529 | ) | 694 | |||||||
(37,589 | ) | (48,310 | ) | 2,350 | ||||||||
Total | $ | (285,205 | ) | $ | (367,835 | ) | $ | 20,556 | ||||
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | ||||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation | $ | 1,068,242 | $ | 371,553 | ||||||||
Property basis differences | — | 130,679 | ||||||||||
ECM under recovered | — | 1,777 | ||||||||||
Regulatory assets associated with AROs | 19,299 | 16,764 | ||||||||||
Pensions and other benefits | 35,200 | 23,769 | ||||||||||
Regulatory assets associated with employee benefit obligations | 67,727 | 33,127 | ||||||||||
Regulatory assets associated with the Kemper IGCC | 61,561 | 30,708 | ||||||||||
Rate differential | 89,040 | 56,074 | ||||||||||
Federal effect of state deferred taxes | 1,279 | 30,615 | ||||||||||
Fuel clause under recovered | 3,288 | — | ||||||||||
Other | 52,215 | 35,583 | ||||||||||
Total | 1,397,851 | 730,649 | ||||||||||
Deferred tax assets — | ||||||||||||
Fuel clause over recovered | — | 7,741 | ||||||||||
Estimated loss on Kemper IGCC | 631,326 | 472,000 | ||||||||||
Pension and other benefits | 92,232 | 57,999 | ||||||||||
Property insurance | 24,315 | 23,693 | ||||||||||
Premium on long-term debt | 20,694 | 23,736 | ||||||||||
Unbilled fuel | 14,535 | 12,136 | ||||||||||
AROs | 19,299 | 16,764 | ||||||||||
Interest rate hedges | 4,544 | 5,094 | ||||||||||
Kemper rate factor - regulatory liability retail | 108,312 | 36,210 | ||||||||||
Property basis difference | 263,430 | — | ||||||||||
ECM over recovered | 905 | — | ||||||||||
Deferred state tax assets | 56,736 | — | ||||||||||
Other | 15,111 | 18,094 | ||||||||||
Total | 1,251,439 | 673,467 | ||||||||||
Total deferred tax liabilities, net | 146,412 | 57,182 | ||||||||||
Portion included in (accrued) prepaid income taxes, net | 121,049 | 15,626 | ||||||||||
Deferred state tax asset | 17,388 | — | ||||||||||
Accumulated deferred income taxes | $ | 284,849 | $ | 72,808 | ||||||||
The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation. | ||||||||||||
At December 31, 2014, the tax-related regulatory assets were $226.2 million. These assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and to taxes applicable to capitalized interest. | ||||||||||||
At December 31, 2014, the tax-related regulatory liabilities were $9.4 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs. | ||||||||||||
In accordance with regulatory requirements, deferred federal ITCs are amortized over the life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of operations. Credits for non-Kemper IGCC related deferred ITCs amortized in this manner amounted to $1.4 million, $1.2 million, and $1.2 million for 2014, 2013, and 2012, respectively. At December 31, 2014, all non-Kemper IGCC ITCs available to reduce federal income taxes payable had been utilized. | ||||||||||||
In 2010, the Company began recognizing ITCs associated with the construction expenditures related to the Kemper IGCC. At December 31, 2014, the Company had $276.4 million in unamortized ITCs associated with the Kemper IGCC, which will be amortized over the life of the Kemper IGCC once placed in service and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65% of the CO2 produced by the Kemper IGCC during operation in accordance with the Internal Revenue Code. A portion of the tax credits will be subject to recapture upon successful completion of SMEPA's proposed purchase of an undivided interest in the Kemper IGCC. | ||||||||||||
Effective Tax Rate | ||||||||||||
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | (35.0 | )% | (35.0 | )% | 35 | % | ||||||
State income tax, net of federal deduction | (4.0 | ) | (3.7 | ) | 1.3 | |||||||
Non-deductible book depreciation | 0.1 | 0.1 | 0.3 | |||||||||
AFUDC-equity | (7.8 | ) | (5.0 | ) | (18.6 | ) | ||||||
Other | 0.1 | (0.1 | ) | (1.2 | ) | |||||||
Effective income tax rate (benefit rate) | (46.6 | )% | (43.7 | )% | 16.8 | % | ||||||
The increase in the Company's 2014 effective tax rate (benefit rate), as compared to 2013, is primarily due to an increase in non-taxable AFUDC equity. The decrease in the Company's 2013 effective tax rate, as compared to 2012, is primarily due to an increase in the estimated losses associated with the Kemper IGCC and an increase in non-taxable AFUDC equity. | ||||||||||||
Unrecognized Tax Benefits | ||||||||||||
Changes during the year in unrecognized tax benefits were as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 3,840 | $ | 5,755 | $ | 4,964 | ||||||
Tax positions from current periods | 58,148 | 226 | 1,186 | |||||||||
Tax positions from prior periods | 102,833 | (2,141 | ) | (26 | ) | |||||||
Settlements with taxing authorities | — | — | (369 | ) | ||||||||
Balance at end of year | $ | 164,821 | $ | 3,840 | $ | 5,755 | ||||||
The increases in tax positions from current periods and prior periods for 2014 relate to deductions for R&E expenditures related to the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle – Section 174 Research and Experimental Deduction" for more information. The decrease in tax positions from prior periods for 2013 relates primarily to the tax accounting method change for repairs related to generation assets. See "Tax Method of Accounting for Repairs" below for additional information. | ||||||||||||
The impact on the Company's effective tax rate, if recognized, is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Tax positions impacting the effective tax rate | $ | 4,341 | $ | 3,840 | $ | 3,656 | ||||||
Tax positions not impacting the effective tax rate | 160,480 | — | 2,099 | |||||||||
Balance of unrecognized tax benefits | $ | 164,821 | $ | 3,840 | $ | 5,755 | ||||||
The tax positions impacting the effective tax rate primarily relate to state income tax credits. The tax positions not impacting the effective tax rate for 2014 relate to a deduction for R&E related to the Kemper IGCC. The tax positions not impacting the effective tax rate for 2012 relate to the tax accounting method change for repairs related to generation assets. These amounts are presented on a gross basis without considering the related federal or state income tax impact. | ||||||||||||
Accrued interest for unrecognized tax benefits was as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Interest accrued at beginning of year | $ | 1,171 | $ | 772 | $ | 680 | ||||||
Interest accrued during the year | 1,698 | 399 | 92 | |||||||||
Balance at end of year | $ | 2,869 | $ | 1,171 | $ | 772 | ||||||
The Company classifies interest on tax uncertainties as interest expense. The Company did not accrue any penalties on uncertain tax positions. | ||||||||||||
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. | ||||||||||||
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011. | ||||||||||||
Tax Method of Accounting for Repairs | ||||||||||||
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company's financial statements. | ||||||||||||
Southern Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
INCOME TAXES | INCOME TAXES | |||||||||||
On behalf of the Company, Southern Company files a consolidated federal income tax return and combined state income tax returns for the States of Alabama, Georgia, and Mississippi. In addition, the Company files separate company income tax returns for the States of Florida, New Mexico, South Carolina, and Tennessee. Unitary income tax returns are filed for the States of California, North Carolina, and Texas. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. | ||||||||||||
Current and Deferred Income Taxes | ||||||||||||
Details of income tax provisions are as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal — | ||||||||||||
Current | $ | 178.6 | $ | (120.2 | ) | $ | (133.1 | ) | ||||
Deferred | (166.0 | ) | 158.7 | 210.4 | ||||||||
12.6 | 38.5 | 77.3 | ||||||||||
State — | ||||||||||||
Current | (13.8 | ) | (5.2 | ) | (3.0 | ) | ||||||
Deferred | (2.0 | ) | 12.6 | 18.3 | ||||||||
(15.8 | ) | 7.4 | 15.3 | |||||||||
Total | $ | (3.2 | ) | $ | 45.9 | $ | 92.6 | |||||
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | ||||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation and other property basis differences | $ | 1,006.50 | $ | 829.5 | ||||||||
Basis difference on asset transfers | 2.6 | 2.8 | ||||||||||
Levelized capacity revenues | 17.1 | 11.2 | ||||||||||
Other | 5.7 | 0.9 | ||||||||||
Total | 1,031.90 | 844.4 | ||||||||||
Deferred tax assets — | ||||||||||||
Federal effect of state deferred taxes | 28.9 | 29.7 | ||||||||||
Net basis difference on federal ITCs | 101.5 | 58 | ||||||||||
Alternative minimum tax carryforward | 15 | 1.1 | ||||||||||
Unrealized tax credits | 305.2 | — | ||||||||||
Unrealized loss on interest rate swaps | 6.1 | 11.2 | ||||||||||
Levelized capacity revenues | 4.9 | 6 | ||||||||||
Deferred state tax assets | 14.5 | 17 | ||||||||||
Other | 4.1 | 4.7 | ||||||||||
Total | 480.2 | 127.7 | ||||||||||
Valuation Allowance | (7.5 | ) | (7.5 | ) | ||||||||
Net deferred income tax assets | 472.7 | 120.2 | ||||||||||
Total deferred tax liabilities, net | 559.2 | 724.2 | ||||||||||
Portion included in current assets/(liabilities), net | 303.6 | 0.2 | ||||||||||
Accumulated deferred income taxes | $ | 862.8 | $ | 724.4 | ||||||||
Deferred tax liabilities are the result of property related timing differences. | ||||||||||||
The application of bonus depreciation provisions in current tax law has significantly increased deferred tax liabilities related to accelerated depreciation. | ||||||||||||
Deferred tax assets consist primarily of timing differences related to net basis differences on federal ITCs and the carryforward of unrealized federal ITCs. | ||||||||||||
At December 31, 2014 and December 31, 2013, the Company had state net operating loss (NOL) carryforwards of $246.6 million and $240.8 million, respectively. The NOL carryforwards resulted in deferred tax assets of $9.4 million as of December 31, 2014 and $11.0 million as of December 31, 2013. The Company has established a valuation allowance due to the remote likelihood that the full tax benefits will be realized. During 2014, the estimated amount of NOL utilization decreased resulting in a $15.1 million increase in the valuation allowance. The increase in income tax expense resulting from the higher valuation allowance was offset by the net income impact of a decrease in the deferred tax balance due to a reduction in the state's statutory tax rate. | ||||||||||||
Of the NOL balance at December 31, 2014, approximately $87.0 million will expire in 2015 and $40.0 million will expire in 2017. | ||||||||||||
Effective Tax Rate | ||||||||||||
A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | ||||||
State income tax, net of federal deduction | (6.0 | ) | 2.2 | 3.7 | ||||||||
Amortization of ITC | (4.3 | ) | (1.7 | ) | (1.0 | ) | ||||||
ITC basis difference | (27.7 | ) | (14.5 | ) | (2.6 | ) | ||||||
Other | 1.1 | 0.3 | (0.6 | ) | ||||||||
Effective income tax rate | (1.9 | )% | 21.3 | % | 34.5 | % | ||||||
The Company's effective tax rate decreased in 2014 primarily due to increased benefits from federal ITCs related to Plants Adobe, Macho Springs, and Imperial Valley. The Company's effective tax rate decreased in 2013 primarily due to tax benefits from federal ITCs related to Plants Campo Verde and Spectrum. | ||||||||||||
In 2009, President Obama signed into law the ARRA. Major tax incentives in the ARRA included renewable energy incentives. The ATRA retroactively extended several renewable energy incentives through 2013, including extending federal ITCs for biomass projects which began construction before January 1, 2014. | ||||||||||||
The Company received cash related to federal ITCs under the renewable energy initiatives of $73.5 million in tax year 2014, $158.1 million in tax year 2013, and $45.0 million in tax year 2012. The tax benefit of the related basis difference reduced income tax expense by $47.5 million in 2014, $31.3 million in 2013, and $7.8 million in 2012. | ||||||||||||
See Note 1 under "Income and Other Taxes" for additional information. | ||||||||||||
Unrecognized Tax Benefits | ||||||||||||
Changes during the year in unrecognized tax benefits were as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 1.5 | $ | 2.9 | $ | 2.6 | ||||||
Tax positions increase from current periods | 4.7 | 1.6 | 0.7 | |||||||||
Tax positions decrease from prior periods | (1.5 | ) | (3.0 | ) | (0.2 | ) | ||||||
Reductions due to settlements | — | — | (0.2 | ) | ||||||||
Balance at end of year | $ | 4.7 | $ | 1.5 | $ | 2.9 | ||||||
The increase in tax positions from current periods for 2014 and 2013 and the decrease from prior periods in 2014 relates to federal ITCs. The decrease in tax positions from prior periods for 2013 relates to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. | ||||||||||||
The impact on the Company's effective tax rate, if recognized, is as follows: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Tax positions impacting the effective tax rate | $4.70 | $1.50 | $0.30 | |||||||||
Tax positions not impacting the effective tax rate | — | — | 2.6 | |||||||||
Balance of unrecognized tax benefits | $4.70 | $1.50 | $2.90 | |||||||||
The tax positions impacting the effective tax rate for 2014 and 2013 relate to federal ITCs. The tax positions not impacting the effective tax rate for 2012 related to the tax accounting method change for repairs-generation assets. See "Tax Method of Accounting for Repairs" herein for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact. | ||||||||||||
The Company classifies interest on tax uncertainties as interest expense. Accrued interest for unrecognized tax benefits was immaterial for all periods presented. The Company did not accrue any penalties on uncertain tax positions. | ||||||||||||
It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined. | ||||||||||||
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 federal income tax return and has received a partial acceptance letter from the IRS; however, the IRS has not finalized its audit. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2010. | ||||||||||||
Tax Method of Accounting for Repairs | ||||||||||||
In 2011, the IRS published regulations on the deduction and capitalization of expenditures related to tangible property that generally apply for tax years beginning on or after January 1, 2014. Additionally, in April 2013, the IRS issued Revenue Procedure 2013-24, which provides guidance for taxpayers related to the deductibility of repair costs associated with generation assets. Based on a review of the regulations, Southern Company incorporated provisions related to repair costs for generation assets into its consolidated 2012 federal income tax return and reversed all related unrecognized tax positions. In September 2013, the IRS issued Treasury Decision 9636, "Guidance Regarding Deduction and Capitalization of Expenditures Related to Tangible Property," which are final tangible property regulations applicable to taxable years beginning on or after January 1, 2014. Southern Company continues to review this guidance; however, these regulations are not expected to have a material impact on the Company's financial statements. |
Financing
Financing | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
FINANCING | FINANCING | |||||||||||||||||||||||||||||||||||||||
Long-Term Debt Payable to an Affiliated Trust | ||||||||||||||||||||||||||||||||||||||||
Alabama Power has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes totaling $206 million as of December 31, 2014 and 2013, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. Alabama Power considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At each of December 31, 2014 and 2013, trust preferred securities of $200 million were outstanding. | ||||||||||||||||||||||||||||||||||||||||
Securities Due Within One Year | ||||||||||||||||||||||||||||||||||||||||
A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows: | ||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
Senior notes | $ | 2,375 | $ | 428 | ||||||||||||||||||||||||||||||||||||
Other long-term debt | 775 | 12 | ||||||||||||||||||||||||||||||||||||||
Pollution control revenue bonds | 152 | — | ||||||||||||||||||||||||||||||||||||||
Capitalized leases | 31 | 29 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 3,333 | $ | 469 | ||||||||||||||||||||||||||||||||||||
Maturities through 2019 applicable to total long-term debt are as follows: $3.33 billion in 2015; $1.83 billion in 2016; $1.55 billion in 2017; $862 million in 2018; and $1.21 billion in 2019. | ||||||||||||||||||||||||||||||||||||||||
Subsequent to December 31, 2014, Alabama Power announced the redemption of $250 million aggregate principal amount of its Series DD 5.65% Senior Notes due March 15, 2035 that will occur on March 16, 2015. | ||||||||||||||||||||||||||||||||||||||||
Bank Term Loans | ||||||||||||||||||||||||||||||||||||||||
Southern Company and certain of the traditional operating companies have entered into various floating rate bank term loan agreements for loans bearing interest based on one-month LIBOR. At December 31, 2014, Mississippi Power had outstanding bank term loans totaling $775 million, which are reflected in the statements of capitalization as long-term debt. At December 31, 2013, Mississippi Power had outstanding bank term loans totaling $525 million and Georgia Power had outstanding bank term loans totaling $400 million. | ||||||||||||||||||||||||||||||||||||||||
In January 2014, Mississippi Power entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power’s continuous construction program. | ||||||||||||||||||||||||||||||||||||||||
In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million. | ||||||||||||||||||||||||||||||||||||||||
In June 2014, Southern Company entered into a 90-day floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including the investment by Southern Company in its subsidiaries. This bank loan was repaid in August 2014. | ||||||||||||||||||||||||||||||||||||||||
The outstanding bank loans as of December 31, 2014, all of which relate to Mississippi Power, have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts, other hybrid securities, and any securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2014, Mississippi Power was in compliance with its debt limits. | ||||||||||||||||||||||||||||||||||||||||
DOE Loan Guarantee Borrowings | ||||||||||||||||||||||||||||||||||||||||
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB. | ||||||||||||||||||||||||||||||||||||||||
Proceeds of advances made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. | ||||||||||||||||||||||||||||||||||||||||
All borrowings under the FFB Credit Facility are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property. | ||||||||||||||||||||||||||||||||||||||||
Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%. | ||||||||||||||||||||||||||||||||||||||||
On February 20, 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility. | ||||||||||||||||||||||||||||||||||||||||
On December 11, 2014, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $200 million. The interest rate applicable to the $200 million advance in December 2014 under the FFB Credit Facility is 3.002% for an interest period that extends to 2044. | ||||||||||||||||||||||||||||||||||||||||
Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, compliance with the Cargo Preference Act of 1954, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. | ||||||||||||||||||||||||||||||||||||||||
Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default. | ||||||||||||||||||||||||||||||||||||||||
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable. | ||||||||||||||||||||||||||||||||||||||||
In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4. | ||||||||||||||||||||||||||||||||||||||||
Senior Notes | ||||||||||||||||||||||||||||||||||||||||
Southern Company and its subsidiaries issued a total of $1.4 billion of senior notes in 2014. Southern Company issued $750 million and its subsidiaries issued a total of $600 million. The proceeds of these issuances were used to repay long-term indebtedness, to repay short-term indebtedness, and for other general corporate purposes, including the applicable subsidiaries' continuous construction programs. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, Southern Company and its subsidiaries had a total of $18.2 billion and $17.3 billion, respectively, of senior notes outstanding. At December 31, 2014 and 2013, Southern Company had a total of $2.2 billion and $1.8 billion, respectively, of senior notes outstanding. | ||||||||||||||||||||||||||||||||||||||||
Since Southern Company is a holding company, the right of Southern Company and, hence, the right of creditors of Southern Company (including holders of Southern Company senior notes) to participate in any distribution of the assets of any subsidiary of Southern Company, whether upon liquidation, reorganization or otherwise, is subject to prior claims of creditors and preferred and preference stockholders of such subsidiary. | ||||||||||||||||||||||||||||||||||||||||
Pollution Control Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
Pollution control obligations represent loans to the traditional operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of pollution control bonds issued by public authorities. The traditional operating companies had $3.2 billion of outstanding pollution control revenue bonds at December 31, 2014 and 2013. The traditional operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. | ||||||||||||||||||||||||||||||||||||||||
Plant Daniel Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
In 2011, in connection with Mississippi Power's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, Mississippi Power assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. See "Assets Subject to Lien" herein for additional information. | ||||||||||||||||||||||||||||||||||||||||
Other Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
Other revenue bond obligations represent loans to Mississippi Power from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCC and related facilities. | ||||||||||||||||||||||||||||||||||||||||
In November 2013, the MBFC entered into an agreement to issue up to $33.75 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013A (Mississippi Power Company Project) and up to $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013B (Mississippi Power Company Project) for the benefit of Mississippi Power. In May 2014 and August 2014, the MBFC issued $12.3 million and $10.5 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. In December 2014, the MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A of $22.87 million and Series 2013B of $11.25 million were paid at maturity. | ||||||||||||||||||||||||||||||||||||||||
Mississippi Power had $50 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2014 and 2013. Mississippi Power had no obligation at December 31, 2014 and $11.3 million of such obligations related to taxable revenue bonds outstanding at December 31, 2013. Such amounts are reflected in the statements of capitalization as long-term senior notes and debt. | ||||||||||||||||||||||||||||||||||||||||
Mississippi Power's agreements relating to its taxable revenue bonds include covenants limiting debt levels consistent with those described above under "Bank Term Loans." | ||||||||||||||||||||||||||||||||||||||||
Capital Leases | ||||||||||||||||||||||||||||||||||||||||
Assets acquired under capital leases are recorded in the balance sheets as utility plant in service and the related obligations are classified as long-term debt. | ||||||||||||||||||||||||||||||||||||||||
In September 2013, Mississippi Power entered into a nitrogen supply agreement for the air separation unit of the Kemper IGCC, which resulted in a capital lease obligation at December 31, 2014 of approximately $80 million with an annual interest rate of 4.9%. Amortization of the capital lease asset for the air separation unit will begin when the Kemper IGCC is placed in service. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, the capitalized lease obligations for Georgia Power's corporate headquarters building were $40 million and $45 million, respectively, with an annual interest rate of 7.9% for both years. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, Alabama Power had a capitalized lease obligation of $5 million for a natural gas pipeline with an annual interest rate of 6.9%. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, a subsidiary of Southern Company had capital lease obligations of approximately $34 million and $30 million, respectively, for certain computer equipment including desktops, laptops, servers, printers, and storage devices with annual interest rates that range from 1.4% to 3.2%. | ||||||||||||||||||||||||||||||||||||||||
Other Obligations | ||||||||||||||||||||||||||||||||||||||||
In 2012, January 2014, and October 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 10.134% per annum for 2014, 9.932% per annum for 2013, and 9.967% per annum for 2012, and are refundable to SMEPA upon termination of the APA related to such purchase or within 15 days of a request by SMEPA for a full or partial refund. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits. | ||||||||||||||||||||||||||||||||||||||||
Assets Subject to Lien | ||||||||||||||||||||||||||||||||||||||||
Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. | ||||||||||||||||||||||||||||||||||||||||
Gulf Power has granted one or more liens on certain of its property in connection with the issuance of certain series of pollution control revenue bonds with an outstanding principal amount of $41 million as of December 31, 2014. | ||||||||||||||||||||||||||||||||||||||||
The revenue bonds assumed in conjunction with Mississippi Power's purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. See "Plant Daniel Revenue Bonds" herein for additional information. | ||||||||||||||||||||||||||||||||||||||||
See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of Georgia Power that are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. | ||||||||||||||||||||||||||||||||||||||||
Bank Credit Arrangements | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, committed credit arrangements with banks were as follows: | ||||||||||||||||||||||||||||||||||||||||
Expires | Executable Term Loans | Due Within | ||||||||||||||||||||||||||||||||||||||
One Year | ||||||||||||||||||||||||||||||||||||||||
Company | 2015 | 2016 | 2017 | 2018 | Total | Unused | One | Two | Term Out | No Term Out | ||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||||||||||||||||||||||||||
Southern Company | $ | — | $ | — | $ | — | $ | 1,000 | $ | 1,000 | $ | 1,000 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||
Alabama Power | 228 | 50 | — | 1,030 | 1,308 | 1,308 | 58 | — | 58 | 170 | ||||||||||||||||||||||||||||||
Georgia Power | — | 150 | — | 1,600 | 1,750 | 1,736 | — | — | — | — | ||||||||||||||||||||||||||||||
Gulf Power | 80 | 165 | 30 | — | 275 | 275 | 50 | — | 50 | 30 | ||||||||||||||||||||||||||||||
Mississippi Power | 135 | 165 | — | — | 300 | 300 | 25 | 40 | 65 | 70 | ||||||||||||||||||||||||||||||
Southern Power | — | — | — | 500 | 500 | 488 | — | — | — | — | ||||||||||||||||||||||||||||||
Other | 70 | — | — | — | 70 | 70 | 20 | — | 20 | 50 | ||||||||||||||||||||||||||||||
Total | $ | 513 | $ | 530 | $ | 30 | $ | 4,130 | $ | 5,203 | $ | 5,177 | $ | 153 | $ | 40 | $ | 193 | $ | 320 | ||||||||||||||||||||
Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/4 of 1% for Southern Company, the traditional operating companies, and Southern Power. Compensating balances are not legally restricted from withdrawal. | ||||||||||||||||||||||||||||||||||||||||
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew their bank credit arrangements as needed, prior to expiration. | ||||||||||||||||||||||||||||||||||||||||
Most of these bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes the long-term debt payable to affiliated trusts and, in certain arrangements, other hybrid securities and, for Mississippi Power, any securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2014, Southern Company, the traditional operating companies, and Southern Power were each in compliance with their respective debt limit covenants. | ||||||||||||||||||||||||||||||||||||||||
A portion of the $5.2 billion unused credit with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2014 was approximately $1.8 billion. In addition, at December 31, 2014, the traditional operating companies had $476 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. As of December 31, 2014, $98 million of certain pollution control revenue bonds of Georgia Power were reclassified to securities due within one year in anticipation of their redemption in connection with unit retirement decisions. See Note 3 under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" for additional information. | ||||||||||||||||||||||||||||||||||||||||
Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. | ||||||||||||||||||||||||||||||||||||||||
Details of short-term borrowings were as follows: | ||||||||||||||||||||||||||||||||||||||||
Short-term Debt at the End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount | Weighted | |||||||||||||||||||||||||||||||||||||||
Outstanding | Average | |||||||||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||||||||||
Rate | ||||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 803 | 0.3 | % | ||||||||||||||||||||||||||||||||||||
Short-term bank debt | — | — | % | |||||||||||||||||||||||||||||||||||||
Total | $ | 803 | 0.3 | % | ||||||||||||||||||||||||||||||||||||
December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 1,082 | 0.2 | % | ||||||||||||||||||||||||||||||||||||
Short-term bank debt | 400 | 0.9 | % | |||||||||||||||||||||||||||||||||||||
Total | $ | 1,482 | 0.4 | % | ||||||||||||||||||||||||||||||||||||
Redeemable Preferred Stock of Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
Each of the traditional operating companies has issued preferred and/or preference stock. The preferred stock of Alabama Power and Mississippi Power contains a feature that allows the holders to elect a majority of such subsidiary's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power and Mississippi Power, this preferred stock is presented as "Redeemable Preferred Stock of Subsidiaries" in a manner consistent with temporary equity under applicable accounting standards. The preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power do not contain such a provision. As a result, under applicable accounting standards, the preferred and preference stock at Georgia Power and the preference stock at Alabama Power and Gulf Power are presented as "noncontrolling interest," a separate component of "Stockholders' Equity," on Southern Company's balance sheets, statements of capitalization, and statements of stockholders' equity. | ||||||||||||||||||||||||||||||||||||||||
There were no changes for the years ended December 31, 2014 and 2013 in redeemable preferred stock of subsidiaries for Southern Company. | ||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
FINANCING | FINANCING | |||||||||||||||||||||||||||||||||||||||
Long-Term Debt Payable to an Affiliated Trust | ||||||||||||||||||||||||||||||||||||||||
The Company has formed a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to the Company through the issuance of junior subordinated notes totaling $206 million as of December 31, 2014 and 2013, which constitute substantially all of the assets of this trust and are reflected in the balance sheets as long-term debt payable. The Company considers that the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constitute a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. At each of December 31, 2014 and 2013, trust preferred securities of $200 million were outstanding. See Note 1 under "Variable Interest Entities" for additional information on the accounting treatment for this trust and the related securities. | ||||||||||||||||||||||||||||||||||||||||
Securities Due Within One Year | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, the Company had $454 million of senior notes and pollution control revenue bonds due within one year. At December 31, 2013, the Company had no scheduled maturities of senior notes or pollution control revenue bonds due within one year. | ||||||||||||||||||||||||||||||||||||||||
Maturities of senior notes and pollution control revenue bonds through 2019 applicable to total long-term debt are as follows: $454 million in 2015; $200 million in 2016; $561 million in 2017; and $200 million in 2019. There are no scheduled maturities in 2018. | ||||||||||||||||||||||||||||||||||||||||
Subsequent to December 31, 2014, the Company announced the redemption of $250 million aggregate principal amount of its Series DD 5.65% Senior Notes due March 15, 2035 that will occur on March 16, 2015. | ||||||||||||||||||||||||||||||||||||||||
Pollution Control Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
Pollution control obligations represent loans to the Company from public authorities of funds or installment purchases of pollution control and solid waste disposal facilities financed by funds derived from sales by public authorities of revenue bonds. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. In December 2014, the Company incurred obligations related to the issuance of $254 million of The Industrial Development Board of the Town of Columbia, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 2014 – A, Series 2014 – B, Series 2014 – C, and Series 2014 – D due December 1, 2037. The proceeds were used to refund in December 2014 approximately $254 million of The Industrial Development Board of the Town of Columbia, Pollution Control Revenue Refunding Bonds (Alabama Power Company Project), Series 1995 – A, 1995 – B, 1995 – C, 1995 – D, 1995 – E, 1996 – A, 1999 – A, 1999 – B, and 1999 – C. | ||||||||||||||||||||||||||||||||||||||||
The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2014 and 2013 was $1.2 billion, respectively. | ||||||||||||||||||||||||||||||||||||||||
Senior Notes | ||||||||||||||||||||||||||||||||||||||||
In August 2014, the Company issued $400 million aggregate principal amount of Series 2014A 4.150% Senior Notes due August 15, 2044. The proceeds were used for general corporate purposes, including the Company's continuous construction program. | ||||||||||||||||||||||||||||||||||||||||
During 2014, the Company entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $200 million. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, the Company had $5.3 billion and $4.9 billion of senior notes outstanding, respectively. As of December 31, 2014, the Company did not have any outstanding secured debt. | ||||||||||||||||||||||||||||||||||||||||
Outstanding Classes of Capital Stock | ||||||||||||||||||||||||||||||||||||||||
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized and outstanding. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary and involuntary dissolution. The preferred stock and Class A preferred stock of the Company contain a feature that allows the holders to elect a majority of the Company's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, the preferred stock and Class A preferred stock is presented as "Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The preference stock does not contain such a provision that would allow the holders to elect a majority of the Company's board. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. | ||||||||||||||||||||||||||||||||||||||||
The Company's preferred stock is subject to redemption at a price equal to the par value plus a premium. The Company's Class A preferred stock is subject to redemption at a price equal to the stated capital. Certain series of the Company's preference stock are subject to redemption at a price equal to the stated capital plus a make-whole premium based on the present value of the liquidation amount and future dividends to the first stated capital redemption date and the other series of preference stock are subject to redemption at a price equal to the stated capital. All series of the Company's preferred stock currently are subject to redemption at the option of the Company. Information for each outstanding series is in the table below: | ||||||||||||||||||||||||||||||||||||||||
Preferred/Preference Stock | Par Value/Stated Capital Per Share | Shares Outstanding | Redemption Price Per Share | |||||||||||||||||||||||||||||||||||||
4.92% Preferred Stock | $100 | 80,000 | $103.23 | |||||||||||||||||||||||||||||||||||||
4.72% Preferred Stock | $100 | 50,000 | $102.18 | |||||||||||||||||||||||||||||||||||||
4.64% Preferred Stock | $100 | 60,000 | $103.14 | |||||||||||||||||||||||||||||||||||||
4.60% Preferred Stock | $100 | 100,000 | $104.20 | |||||||||||||||||||||||||||||||||||||
4.52% Preferred Stock | $100 | 50,000 | $102.93 | |||||||||||||||||||||||||||||||||||||
4.20% Preferred Stock | $100 | 135,115 | $105.00 | |||||||||||||||||||||||||||||||||||||
5.83% Class A Preferred Stock | $25 | 1,520,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
5.20% Class A Preferred Stock | $25 | 6,480,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
5.30% Class A Preferred Stock | $25 | 4,000,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
5.625% Preference Stock | $25 | 6,000,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
6.450% Preference Stock | $25 | 6,000,000 | * | |||||||||||||||||||||||||||||||||||||
6.500% Preference Stock | $25 | 2,000,000 | * | |||||||||||||||||||||||||||||||||||||
* | Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital | |||||||||||||||||||||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||||||||||||||||||||||
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. | ||||||||||||||||||||||||||||||||||||||||
Assets Subject to Lien | ||||||||||||||||||||||||||||||||||||||||
During 2014, all outstanding pollution control revenue bonds pursuant to which the Company granted liens on certain property were redeemed. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. | ||||||||||||||||||||||||||||||||||||||||
Bank Credit Arrangements | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, committed credit arrangements with banks were as follows: | ||||||||||||||||||||||||||||||||||||||||
Expires(a) | Executable | Due Within One Year | ||||||||||||||||||||||||||||||||||||||
Term-Loans | ||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2018 | Total | Unused | One | Two | Term Out | No Term Out | ||||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$ | 228 | $ | 50 | $ | 1,030 | $ | 1,308 | $ | 1,308 | $ | 58 | $ | — | $ | 58 | $ | 170 | |||||||||||||||||||||||
(a) | No credit arrangements expire in 2017. | |||||||||||||||||||||||||||||||||||||||
The Company expects to renew its bank credit agreements as needed, prior to expiration. Most of the bank credit arrangements require payment of a commitment fee based on the unused portion of the commitments or the maintenance of compensating balances with the banks. Commitment fees average less than 1/10 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. | ||||||||||||||||||||||||||||||||||||||||
Most of the Company's bank credit arrangements contain covenants that limit the Company's debt to 65% of total capitalization, as defined in the arrangements. For purposes of calculating these covenants, any long-term notes payable to affiliated trusts are excluded from debt but included in capitalization. Exceeding this debt level would result in a default under the credit arrangements. At December 31, 2014, the Company was in compliance with the debt limit covenants. | ||||||||||||||||||||||||||||||||||||||||
A portion of the unused credit with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was $784 million as of December 31, 2014. In addition, at December 31, 2014, the Company had $280 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. | ||||||||||||||||||||||||||||||||||||||||
The Company borrows through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. The Company may also make short-term borrowings through various other arrangements with banks. At December 31, 2014 and 2013, there was no short-term debt outstanding. At December 31, 2014, the Company had regulatory approval to have outstanding up to $2 billion of short-term borrowings. | ||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
FINANCING | FINANCING | |||||||||||||||||||||||||||||||||||||||
Securities Due Within One Year | ||||||||||||||||||||||||||||||||||||||||
A summary of scheduled maturities of long-term debt due within one year at December 31 was as follows: | ||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
Senior notes | $ | 1,050 | $ | — | ||||||||||||||||||||||||||||||||||||
Pollution control revenue bonds | 98 | — | ||||||||||||||||||||||||||||||||||||||
Capital lease | 6 | 5 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 1,154 | $ | 5 | ||||||||||||||||||||||||||||||||||||
Maturities through 2019 applicable to total long-term debt are as follows: $1.2 billion in 2015; $710 million in 2016; $457 million in 2017; $257 million in 2018; and $508 million in 2019. | ||||||||||||||||||||||||||||||||||||||||
Senior Notes | ||||||||||||||||||||||||||||||||||||||||
The Company did not issue any unsecured senior notes in 2014. At December 31, 2014 and 2013, the Company had $6.9 billion of senior notes outstanding. These senior notes are effectively subordinated to all secured debt of the Company, which aggregated $1.2 billion and $45 million at December 31, 2014 and 2013, respectively. As of December 31, 2014, the Company's secured debt included borrowings of $1.2 billion guaranteed by the DOE and capital leases. As of December 31, 2013, the Company's secured debt was related to capital lease obligations. See Note 7 for additional information. | ||||||||||||||||||||||||||||||||||||||||
See "DOE Loan Guarantee Borrowings" herein for additional information. | ||||||||||||||||||||||||||||||||||||||||
Pollution Control Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2014 and 2013 was $1.6 billion and $1.7 billion, respectively. Proceeds from certain issuances are restricted until qualifying expenditures are incurred. | ||||||||||||||||||||||||||||||||||||||||
In July 2014, the Company reoffered to the public $40 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2009, which had been previously purchased and held by the Company since 2010. | ||||||||||||||||||||||||||||||||||||||||
Bank Term Loans | ||||||||||||||||||||||||||||||||||||||||
In February 2014, the Company repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million. At December 31, 2014, the Company had no bank term loans outstanding. | ||||||||||||||||||||||||||||||||||||||||
DOE Loan Guarantee Borrowings | ||||||||||||||||||||||||||||||||||||||||
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), the Company and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of the Company under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, the Company, and the FFB and a related promissory note (FFB Promissory Note). The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which the Company may make term loan borrowings through the FFB. | ||||||||||||||||||||||||||||||||||||||||
Proceeds of advances made under the FFB Credit Facility will be used to reimburse the Company for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. | ||||||||||||||||||||||||||||||||||||||||
All borrowings under the FFB Credit Facility are full recourse to the Company, and the Company is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. The Company's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) the Company's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on the Company's ability to grant liens on other property. | ||||||||||||||||||||||||||||||||||||||||
Advances may be requested under the FFB Credit Facility on a quarterly basis through 2020. The final maturity date for each advance under the FFB Credit Facility is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facility will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%. | ||||||||||||||||||||||||||||||||||||||||
On February 20, 2014, the Company made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, the Company incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility. | ||||||||||||||||||||||||||||||||||||||||
On December 11, 2014, the Company made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $200 million. The interest rate applicable to the $200 million advance in December 2014 under the FFB Credit Facility is 3.002% for an interest period that extends to 2044. | ||||||||||||||||||||||||||||||||||||||||
Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, compliance with the Cargo Preference Act of 1954, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs. | ||||||||||||||||||||||||||||||||||||||||
Under the Loan Guarantee Agreement, the Company is subject to customary borrower affirmative and negative covenants and events of default. In addition, the Company is subject to project-related reporting requirements and other project-specific covenants and events of default. | ||||||||||||||||||||||||||||||||||||||||
In the event certain mandatory prepayment events occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and the Company will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. The Company also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Promissory Note, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable. | ||||||||||||||||||||||||||||||||||||||||
In connection with any cancellation of Plant Vogtle Units 3 and 4 that results in a mandatory prepayment event, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume the Company's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of the Company's ownership interest in Plant Vogtle Units 3 and 4. | ||||||||||||||||||||||||||||||||||||||||
Capital Leases | ||||||||||||||||||||||||||||||||||||||||
Assets acquired under capital leases are recorded in the balance sheets as utility plant in service, and the related obligations are classified as long-term debt. At December 31, 2014 and 2013, the Company had a capital lease asset for its corporate headquarters building of $61 million, with accumulated depreciation at December 31, 2014 and 2013 of $21 million and $16 million, respectively. At December 31, 2014 and 2013, the capitalized lease obligation was $40 million and $45 million, respectively, with an annual interest rate of 7.9% for both years. For ratemaking purposes, the Georgia PSC has allowed only the lease payments in cost of service. The difference between the accrued expense and the lease payments allowed for ratemaking purposes has been deferred and is being amortized to expense as ordered by the Georgia PSC. The annual expense incurred for all capital leases was not material for any year presented. See Note 7 under "Fuel and Purchased Power Agreements" for additional information on capital lease PPAs that become effective in 2015. | ||||||||||||||||||||||||||||||||||||||||
Assets Subject to Lien | ||||||||||||||||||||||||||||||||||||||||
See "DOE Loan Guarantee Borrowings" above for information regarding certain borrowings of the Company that are secured by a first priority lien on (i) the Company’s 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) the Company's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. | ||||||||||||||||||||||||||||||||||||||||
See "Capital Leases" above for information regarding certain assets held under capital leases. | ||||||||||||||||||||||||||||||||||||||||
Outstanding Classes of Capital Stock | ||||||||||||||||||||||||||||||||||||||||
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company has shares of its Class A preferred stock, preference stock, and common stock outstanding. The Company's Class A preferred stock ranks senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. The outstanding series of the Class A preferred stock is subject to redemption at the option of the Company at any time at a redemption price equal to 100% of the par value. In addition, on or after October 1, 2017, the Company may redeem the outstanding series of the preference stock at a redemption price equal to 100% of the par value. With respect to any redemption of the preference stock prior to October 1, 2017, the redemption price includes a make-whole premium based on the present value of the liquidation amount and future dividends through the first par redemption date. | ||||||||||||||||||||||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||||||||||||||||||||||
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. | ||||||||||||||||||||||||||||||||||||||||
Bank Credit Arrangements | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, committed credit arrangements with banks were as follows: | ||||||||||||||||||||||||||||||||||||||||
Expires(a) | ||||||||||||||||||||||||||||||||||||||||
2016 | 2018 | Total | Unused | |||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$150 | $1,600 | $1,750 | $1,736 | |||||||||||||||||||||||||||||||||||||
(a) | No credit arrangements expire in 2015 or 2017. | |||||||||||||||||||||||||||||||||||||||
Subject to applicable market conditions, the Company expects to renew its bank credit arrangements, as needed, prior to expiration. All of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Company. | ||||||||||||||||||||||||||||||||||||||||
The bank credit arrangements contain covenants that limit the Company's debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes certain hybrid securities. | ||||||||||||||||||||||||||||||||||||||||
A portion of the $1.7 billion unused credit with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and its commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2014 was $865 million. In addition, at December 31, 2014, the Company had $118 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. As of December 31, 2014, $98 million of certain pollution control revenue bonds of the Company were reclassified to securities due within one year in anticipation of their redemption in connection with unit retirement decisions. See Note 3 under "Retail Regulatory Matters – Integrated Resource Plans" for additional information. | ||||||||||||||||||||||||||||||||||||||||
The Company makes short-term borrowings primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements described above. The Company may also borrow through various other arrangements with banks. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. | ||||||||||||||||||||||||||||||||||||||||
The Company had $156 million and $1.0 billion of short-term debt outstanding at December 31, 2014 and 2013, respectively. Details of short-term borrowings outstanding were as follows: | ||||||||||||||||||||||||||||||||||||||||
Short-term Debt at the End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount | Weighted | |||||||||||||||||||||||||||||||||||||||
Outstanding | Average | |||||||||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||||||||||
Rate | ||||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 156 | 0.3 | % | ||||||||||||||||||||||||||||||||||||
December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 647 | 0.2 | % | ||||||||||||||||||||||||||||||||||||
Short-term bank debt | 400 | 0.9 | % | |||||||||||||||||||||||||||||||||||||
Total | $ | 1,047 | 0.5 | % | ||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
FINANCING | FINANCING | |||||||||||||||||||||||||||||||||||||||
Securities Due Within One Year | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, the Company had no scheduled maturities of long-term debt due within one year. | ||||||||||||||||||||||||||||||||||||||||
Maturities from 2016 through 2019 applicable to total long-term debt are as follows: $110 million in 2016 and $85 million in 2017. There are no scheduled maturities in 2015, 2018, or 2019. | ||||||||||||||||||||||||||||||||||||||||
Senior Notes | ||||||||||||||||||||||||||||||||||||||||
At each of December 31, 2014 and 2013, the Company had a total of $1.07 billion and $945 million of senior notes outstanding, respectively. These senior notes are effectively subordinate to all secured debt of the Company, which totaled approximately $41 million at December 31, 2014. | ||||||||||||||||||||||||||||||||||||||||
In September 2014, the Company issued $200 million aggregate principal amount of Series 2014A 4.55% Senior Notes due October 1, 2044. The proceeds were used to repay a portion of the Company's outstanding short-term indebtedness, for general corporate purposes, including the Company's continuous construction program and for repayment at maturity $75 million aggregate principal amount of the Company's Series K 4.90% Senior Notes due October 1, 2014. | ||||||||||||||||||||||||||||||||||||||||
Pollution Control Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2014 and 2013 was $309 million and $296 million, respectively. | ||||||||||||||||||||||||||||||||||||||||
In April 2014, the Company executed a loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075 million aggregate principal amount of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for the benefit of the Company. The proceeds were used to redeem $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project). | ||||||||||||||||||||||||||||||||||||||||
In June 2014, the Company reoffered to the public $13 million aggregate principal amount of MBFC Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 2012 (Gulf Power Company Project), which had been previously purchased and held by the Company since December 2013. | ||||||||||||||||||||||||||||||||||||||||
Outstanding Classes of Capital Stock | ||||||||||||||||||||||||||||||||||||||||
The Company currently has preferred stock, Class A preferred stock, preference stock, and common stock authorized. The Company's preferred stock and Class A preferred stock, without preference between classes, rank senior to the Company's preference stock and common stock with respect to payment of dividends and voluntary or involuntary dissolution. No shares of preferred stock or Class A preferred stock were outstanding at December 31, 2014. The Company's preference stock ranks senior to the common stock with respect to the payment of dividends and voluntary or involuntary dissolution. Certain series of the preference stock are subject to redemption at the option of the Company on or after a specified date (typically five or 10 years after the date of issuance) at a redemption price equal to 100% of the liquidation amount of the preference stock. In addition, certain series of the preference stock may be redeemed earlier at a redemption price equal to 100% of the liquidation amount plus a make-whole premium based on the present value of the liquidation amount and future dividends. | ||||||||||||||||||||||||||||||||||||||||
In January 2014, the Company issued 500,000 shares of common stock to Southern Company and realized proceeds of $50 million. The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes, including the Company's continuous construction program. | ||||||||||||||||||||||||||||||||||||||||
Subsequent to December 31, 2014, the Company issued 200,000 shares of common stock to Southern Company and realized proceeds of $20 million. The proceeds were used to repay a portion of the Company's short-term debt and for other general corporate purposes, including the Company's continuous construction program. | ||||||||||||||||||||||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||||||||||||||||||||||
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. | ||||||||||||||||||||||||||||||||||||||||
Assets Subject to Lien | ||||||||||||||||||||||||||||||||||||||||
The Company has granted a lien on its property at Plant Daniel in connection with the issuance of two series of pollution control revenue bonds with an outstanding principal amount of $41 million. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its subsidiaries. | ||||||||||||||||||||||||||||||||||||||||
Bank Credit Arrangements | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, committed credit arrangements with banks were as follows: | ||||||||||||||||||||||||||||||||||||||||
Expires | Executable | Due Within One Year | ||||||||||||||||||||||||||||||||||||||
Term-Loans | ||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | Total | Unused | One | Two | Term Out | No Term Out | ||||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$ | 80 | $ | 165 | $ | 30 | $ | 275 | $ | 275 | $ | 50 | $ | — | $ | 50 | $ | 30 | |||||||||||||||||||||||
Subject to applicable market conditions, the Company expects to renew its bank credit arrangements as needed, prior to expiration. Most of the $275 million of unused credit arrangements with banks provide liquidity support to the Company's variable rate pollution control revenue bonds and commercial paper program. The Company had $69 million of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2014. In addition, at December 31, 2014, the Company had $78 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Most of the bank credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Company. | ||||||||||||||||||||||||||||||||||||||||
Most of these bank credit arrangements contain covenants that limit the Company's debt level to 65% of total capitalization, as defined in the arrangements. For purposes of these definitions, debt excludes certain hybrid securities. At December 31, 2014, the Company was in compliance with these covenants. | ||||||||||||||||||||||||||||||||||||||||
For short-term cash needs, the Company borrows primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements described above. The Company may also borrow through various other arrangements with banks. Commercial paper and short-term bank loans are included in notes payable in the balance sheets. | ||||||||||||||||||||||||||||||||||||||||
Details of short-term borrowings were as follows: | ||||||||||||||||||||||||||||||||||||||||
Commercial Paper at the | ||||||||||||||||||||||||||||||||||||||||
End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount Outstanding | Weighted | |||||||||||||||||||||||||||||||||||||||
Average | ||||||||||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||||||||||
Rate | ||||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | $ | 110 | 0.30% | |||||||||||||||||||||||||||||||||||||
December 31, 2013 | $ | 136 | 0.20% | |||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
FINANCING | FINANCING | |||||||||||||||||||||||||||||||||||||||
Bank Term Loans | ||||||||||||||||||||||||||||||||||||||||
In January 2014, the Company entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including the Company’s continuous construction program. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, the Company had $775 million and $525 million of bank loans outstanding, respectively, which are reflected in the statements of capitalization as securities due within one year and long-term debt. | ||||||||||||||||||||||||||||||||||||||||
These bank loans have covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes any long-term debt payable to affiliated trusts, other hybrid securities, and any securitized debt relating to the securitization of certain costs of the Kemper IGCC. At December 31, 2014, the Company was in compliance with its debt limits. | ||||||||||||||||||||||||||||||||||||||||
Senior Notes | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, the Company had $1.1 billion of senior notes outstanding. These senior notes are effectively subordinated to the secured debt of the Company. See "Plant Daniel Revenue Bonds" below for additional information regarding the Company's secured indebtedness. | ||||||||||||||||||||||||||||||||||||||||
Plant Daniel Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
In 2011, in connection with the Company's election under its operating lease of Plant Daniel Units 3 and 4 to purchase the assets, the Company assumed the obligations of the lessor related to $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021, issued for the benefit of the lessor. These bonds are secured by Plant Daniel Units 3 and 4 and certain related personal property. The bonds were recorded at fair value as of the date of assumption, or $346.1 million, reflecting a premium of $76.1 million. | ||||||||||||||||||||||||||||||||||||||||
Securities Due Within One Year | ||||||||||||||||||||||||||||||||||||||||
A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2014 and 2013 was as follows: | ||||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
Bank term loans | $ | 775 | $ | — | ||||||||||||||||||||||||||||||||||||
Revenue bonds | — | 11.3 | ||||||||||||||||||||||||||||||||||||||
Capitalized leases | 2.7 | 2.5 | ||||||||||||||||||||||||||||||||||||||
Outstanding at December 31 | $ | 777.7 | $ | 13.8 | ||||||||||||||||||||||||||||||||||||
Maturities through 2019 applicable to total long-term debt are as follows: $777.7 million in 2015, $302.8 million in 2016, $37.9 million in 2017, $3.1 million in 2018, and $128.2 million in 2019. | ||||||||||||||||||||||||||||||||||||||||
Pollution Control Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
Pollution control obligations represent loans to the Company from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. The Company is required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. The amount of tax-exempt pollution control revenue bonds outstanding at December 31, 2014 and 2013 was $82.7 million. | ||||||||||||||||||||||||||||||||||||||||
Other Revenue Bonds | ||||||||||||||||||||||||||||||||||||||||
Other revenue bond obligations represent loans to the Company from a public authority of funds derived from the sale by such authority of revenue bonds issued to finance a portion of the costs of constructing the Kemper IGCC and related facilities. | ||||||||||||||||||||||||||||||||||||||||
In November 2013, the MBFC entered into an agreement to issue up to $33.75 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013A (Mississippi Power Company Project) and up to $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds, Series 2013B (Mississippi Power Company Project) for the benefit of the Company. In November 2013, the MBFC issued $11.25 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013B for the benefit of the Company. | ||||||||||||||||||||||||||||||||||||||||
In May 2014 and August 2014, the MBFC issued $12.3 million and $10.5 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of the Company and proceeds were used to reimburse the Company for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. In December 2014, the MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A of $22.87 million and Series 2013B of $11.25 million were paid at maturity. The Company had $50.0 million of such obligations outstanding related to tax-exempt revenue bonds at December 31, 2014 and 2013. The Company had no obligation as of December 31, 2014 and $11.3 million of such obligations related to taxable revenue bonds outstanding at December 31, 2013. Such amounts are reflected in the statements of capitalization as long-term senior notes and debt. | ||||||||||||||||||||||||||||||||||||||||
The Company's agreements relating to the taxable revenue bonds include covenants limiting debt levels consistent with those described above under "Bank Term Loans." | ||||||||||||||||||||||||||||||||||||||||
Capital Leases | ||||||||||||||||||||||||||||||||||||||||
In September 2013, the Company entered into an agreement to sell the air separation unit for the Kemper IGCC and also entered into a 20-year nitrogen supply agreement. The nitrogen supply agreement was determined to be a sale/leaseback agreement which resulted in a capital lease obligation at December 31, 2014 of $80.0 million with an annual interest rate of 4.9%. There are no contingent rentals in the contract and a portion of the monthly payment specified in the agreement is related to executory costs for the operation and maintenance of the air separation unit and excluded from the minimum lease payments. The minimum lease payments for 2014 were $6.5 million and will be $6.5 million each year thereafter. Amortization of the capital lease asset for the air separation unit will begin when the Kemper IGCC is placed in service. | ||||||||||||||||||||||||||||||||||||||||
Other Obligations | ||||||||||||||||||||||||||||||||||||||||
In 2012, January 2014, and October 2014, the Company received $150 million, $75 million, and $50 million, respectively, interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at the Company's AFUDC rate adjusted for income taxes, which was 10.134% per annum for 2014, 9.932% per annum for 2013, and 9.967% per annum for 2012, and are refundable to SMEPA upon termination of the APA related to such purchase or within 15 days of a request by SMEPA for a full or partial refund. | ||||||||||||||||||||||||||||||||||||||||
In May 2014, the Company issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including the Company's construction program. This loan was repaid in September 2014. | ||||||||||||||||||||||||||||||||||||||||
Assets Subject to Lien | ||||||||||||||||||||||||||||||||||||||||
The revenue bonds assumed in conjunction with the purchase of Plant Daniel Units 3 and 4 are secured by Plant Daniel Units 3 and 4 and certain related personal property. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy the obligations of Southern Company or another of its other subsidiaries. | ||||||||||||||||||||||||||||||||||||||||
Outstanding Classes of Capital Stock | ||||||||||||||||||||||||||||||||||||||||
The Company currently has preferred stock (including depositary shares which represent one-fourth of a share of preferred stock) and common stock authorized and outstanding. The preferred stock of the Company contains a feature that allows the holders to elect a majority of the Company's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of the Company, this preferred stock is presented as "Cumulative Redeemable Preferred Stock" in a manner consistent with temporary equity under applicable accounting standards. The Company's preferred stock and depositary preferred stock, without preference between classes, rank senior to the Company's common stock with respect to payment of dividends and voluntary or involuntary dissolution. The preferred stock and depositary preferred stock is subject to redemption at the option of the Company at a redemption price equal to 100% of the liquidation amount of the stock. | ||||||||||||||||||||||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||||||||||||||||||||||
The Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. | ||||||||||||||||||||||||||||||||||||||||
Bank Credit Arrangements | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, committed credit arrangements with banks were as follows: | ||||||||||||||||||||||||||||||||||||||||
Expires | Executable | Due Within One Year | ||||||||||||||||||||||||||||||||||||||
Term-Loans | ||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | Total | Unused | One | Two | Term Out | No Term Out | |||||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$135 | $165 | $300 | $300 | $25 | $40 | $65 | $70 | |||||||||||||||||||||||||||||||||
Subject to applicable market conditions, the Company expects to renew its bank credit arrangements, as needed, prior to expiration. | ||||||||||||||||||||||||||||||||||||||||
Most of these bank credit arrangements require payment of commitment fees based on the unused portions of the commitments or to maintain compensating balances with the banks. Commitment fees average less than 1/4 of 1% for the Company. Compensating balances are not legally restricted from withdrawal. | ||||||||||||||||||||||||||||||||||||||||
Most of these bank credit arrangements contain covenants that limit the Company's debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes certain hybrid securities and any securitized debt relating to the securitization of certain costs of the Kemper IGCC. | ||||||||||||||||||||||||||||||||||||||||
A portion of the $300 million unused credit with banks is allocated to provide liquidity support to the Company's variable rate pollution control revenue bonds and its commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of December 31, 2014 was $40.1 million. | ||||||||||||||||||||||||||||||||||||||||
The Company makes short-term borrowings primarily through a commercial paper program that has the liquidity support of the Company's committed bank credit arrangements. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, there was no short-term debt outstanding. | ||||||||||||||||||||||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
FINANCING | FINANCING | |||||||||||||||||||||||||||||||||||||||
Securities Due Within One Year | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, the Company had $525.0 million of senior notes due within one year. In addition, at December 31, 2014, the Company classified as due within one year approximately $0.3 million of long-term debt payable to TRE that is expected to be repaid in 2015. At December 31, 2013, the Company classified approximately $0.6 million of long-term debt payable to TRE as due within one year. | ||||||||||||||||||||||||||||||||||||||||
There are no additional scheduled maturities of long-term debt through 2019. | ||||||||||||||||||||||||||||||||||||||||
Other Long-Term Notes | ||||||||||||||||||||||||||||||||||||||||
During 2014, the Company prepaid $9.5 million of long-term debt payable to TRE and issued $0.1 million due June 15, 2032, $0.8 million due April 30, 2033, $3.9 million due April 30, 2034, and $5.4 million due May 31, 2034 under promissory notes payable to TRE related to the financing of Apex, Campo Verde, Adobe, and Macho Springs, respectively. At December 31, 2014, and 2013, the Company had $18.8 million and $17.8 million, respectively, of long-term debt payable to TRE. | ||||||||||||||||||||||||||||||||||||||||
Senior Notes | ||||||||||||||||||||||||||||||||||||||||
During 2013, Southern Power Company issued $300 million aggregate principal amount of its Series 2013A 5.25% Senior Notes due July 15, 2043. The net proceeds from the sale of the Series 2013A Senior Notes were used to repay a portion of its outstanding short-term indebtedness and for other general corporate purposes, including the Company’s continuous construction program. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014 and 2013, Southern Power Company had $1.6 billion of senior notes outstanding, which included senior notes due within one year. | ||||||||||||||||||||||||||||||||||||||||
Bank Credit Arrangements | ||||||||||||||||||||||||||||||||||||||||
In February 2013, Southern Power Company amended its $500 million committed credit facility (Facility), which extended the maturity date from 2016 to 2018. As of December 31, 2014, the total amount available under the Facility was $488 million. There were no borrowings outstanding under the Facility at December 31, 2013. The Facility does not contain a material adverse change clause at the time of borrowing. Subject to applicable market conditions, Southern Power Company plans to renew the Facility prior to its expiration. | ||||||||||||||||||||||||||||||||||||||||
Southern Power Company is required to pay a commitment fee on the unused balance of the Facility. This fee is less than 1/4 of 1%. The Facility contains a covenant that limits the ratio of debt to capitalization (each as defined in the Facility) to a maximum of 65%. At December 31, 2014, the Company was in compliance with its debt limits. | ||||||||||||||||||||||||||||||||||||||||
Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for the Company's commercial paper program. | ||||||||||||||||||||||||||||||||||||||||
The Company's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes. Commercial paper is included in notes payable in the balance sheets. | ||||||||||||||||||||||||||||||||||||||||
Details of short-term borrowings are shown below. The Company had no short-term borrowings in 2013. | ||||||||||||||||||||||||||||||||||||||||
Commercial Paper at the | ||||||||||||||||||||||||||||||||||||||||
End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount Outstanding | Weighted Average Interest Rate | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | $ | 195 | 0.4 | % | ||||||||||||||||||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||||||||||||||||||||||
Southern Power Company can only pay dividends to Southern Company out of retained earnings or paid-in-capital. | ||||||||||||||||||||||||||||||||||||||||
The indenture related to certain series of Southern Power Company's senior notes also contains certain limitations on the payment of common stock dividends. No dividends may be paid unless, as of the end of any calendar quarter, the Company's projected cash flows from fixed priced capacity PPAs are at least 80% of total projected cash flows for the next 12 months or the Company's debt to capitalization ratio is no greater than 60%. At December 31, 2014, Southern Power Company was in compliance with these ratios and had no other restrictions on its ability to pay dividends. |
Commitments
Commitments | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
COMMITMENTS | COMMITMENTS | |||||||||||||||||||
Fuel and Purchased Power Agreements | ||||||||||||||||||||
To supply a portion of the fuel requirements of the generating plants, the Southern Company system has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2014, 2013, and 2012, the traditional operating companies and Southern Power incurred fuel expense of $6.0 billion, $5.5 billion, and $5.1 billion, respectively, the majority of which was purchased under long-term commitments. Southern Company expects that a substantial amount of the Southern Company system's future fuel needs will continue to be purchased under long-term commitments. | ||||||||||||||||||||
In addition, the Southern Company system has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases or have been used by a third party to secure financing. Total capacity expense under PPAs accounted for as operating leases was $198 million, $157 million, and $171 million for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||
Estimated total obligations under these commitments at December 31, 2014 were as follows: | ||||||||||||||||||||
Operating Leases (1) | Other | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 230 | $ | 11 | ||||||||||||||||
2016 | 234 | 11 | ||||||||||||||||||
2017 | 264 | 10 | ||||||||||||||||||
2018 | 270 | 7 | ||||||||||||||||||
2019 | 274 | 6 | ||||||||||||||||||
2020 and thereafter | 1,980 | 50 | ||||||||||||||||||
Total | $ | 3,252 | $ | 95 | ||||||||||||||||
-1 | A total of $1.1 billion of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. | |||||||||||||||||||
Operating Leases | ||||||||||||||||||||
The Southern Company system has operating lease agreements with various terms and expiration dates. Total rent expense was $118 million, $123 million, and $155 million for 2014, 2013, and 2012, respectively. Southern Company includes any step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. | ||||||||||||||||||||
As of December 31, 2014, estimated minimum lease payments under operating leases were as follows: | ||||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Barges & | Other | Total | ||||||||||||||||||
Railcars | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 50 | $ | 50 | $ | 100 | ||||||||||||||
2016 | 41 | 48 | 89 | |||||||||||||||||
2017 | 18 | 47 | 65 | |||||||||||||||||
2018 | 9 | 35 | 44 | |||||||||||||||||
2019 | 6 | 23 | 29 | |||||||||||||||||
2020 and thereafter | 20 | 228 | 248 | |||||||||||||||||
Total | $ | 144 | $ | 431 | $ | 575 | ||||||||||||||
For the traditional operating companies, a majority of the barge and railcar lease expenses are recoverable through fuel cost recovery provisions. In addition to the above rental commitments, Alabama Power and Georgia Power have obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $53 million. At the termination of the leases, the lessee may renew the lease or exercise its purchase option or the property can be sold to a third party. Alabama Power and Georgia Power expect that the fair market value of the leased property would substantially reduce or eliminate the payments under the residual value obligations. | ||||||||||||||||||||
Guarantees | ||||||||||||||||||||
In December 2013, Georgia Power entered into an agreement that requires Georgia Power to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million. | ||||||||||||||||||||
As discussed above under "Operating Leases," Alabama Power and Georgia Power have entered into certain residual value guarantees. | ||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
COMMITMENTS | COMMITMENTS | |||||||||||||||||||
Fuel and Purchased Power Agreements | ||||||||||||||||||||
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2014, 2013, and 2012, the Company incurred fuel expense of $1.6 billion, $1.6 billion, and $1.5 billion, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. | ||||||||||||||||||||
In addition, the Company has entered into various long-term commitments for the purchase of capacity and electricity, some of which are accounted for as operating leases. Total capacity expense under PPAs accounted for as operating leases was $37 million, $30 million, and $33 million for 2014, 2013, and 2012, respectively. Total estimated minimum long-term obligations at December 31, 2014 were as follows: | ||||||||||||||||||||
Operating | ||||||||||||||||||||
Lease | ||||||||||||||||||||
PPAs | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 37 | ||||||||||||||||||
2016 | 39 | |||||||||||||||||||
2017 | 40 | |||||||||||||||||||
2018 | 41 | |||||||||||||||||||
2019 | 43 | |||||||||||||||||||
2020 and thereafter | 137 | |||||||||||||||||||
Total commitments | $ | 337 | ||||||||||||||||||
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. | ||||||||||||||||||||
Operating Leases | ||||||||||||||||||||
The Company has entered into rental agreements for coal railcars, vehicles, and other equipment with various terms and expiration dates. Total rent expense was $18 million in 2014, $21 million in 2013, and $24 million in 2012. Of these amounts, $14 million, $18 million, and $19 million for 2014, 2013, and 2012, respectively, relate to the railcar leases and are recoverable through the Company's Rate ECR. As of December 31, 2014, estimated minimum lease payments under operating leases were as follows: | ||||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Railcars | Vehicles & Other | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 13 | $ | 3 | $ | 16 | ||||||||||||||
2016 | 11 | 3 | 14 | |||||||||||||||||
2017 | 7 | 3 | 10 | |||||||||||||||||
2018 | 5 | 1 | 6 | |||||||||||||||||
2019 | 5 | — | 5 | |||||||||||||||||
2020 and thereafter | 17 | — | 17 | |||||||||||||||||
Total | $ | 58 | $ | 10 | $ | 68 | ||||||||||||||
In addition to the above rental commitments payments, the Company has potential obligations upon expiration of certain leases with respect to the residual value of the leased property. These leases have terms expiring through 2023 with maximum obligations under these leases of $5 million in 2015, $4 million in 2016, and $12 million in 2020 and thereafter. There are no obligations under these leases in 2017, 2018, and 2019. At the termination of the leases, the lessee may either exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations. | ||||||||||||||||||||
Guarantees | ||||||||||||||||||||
The Company has guaranteed the obligation of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019, and also $100 million of senior notes issued in November 2013, which mature in December 2018. Georgia Power has agreed to reimburse the Company for the pro rata portion of such obligations corresponding to Georgia Power's then proportionate ownership of SEGCO's stock if the Company is called upon to make such payment under its guarantee. See Note 4 for additional information. | ||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
COMMITMENTS | COMMITMENTS | |||||||||||||||||||
Fuel and Purchased Power Agreements | ||||||||||||||||||||
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil and nuclear fuel which are not recognized on the balance sheets. In 2014, 2013, and 2012, the Company incurred fuel expense of $2.5 billion, $2.3 billion, and $2.1 billion, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. | ||||||||||||||||||||
The Company has commitments regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the latter of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. The energy cost is a function of each unit's variable operating costs. Portions of the capacity payments relate to costs in excess of MEAG Power's Plant Vogtle Unit 1 and 2 allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity and energy is included in purchased power, non-affiliates in the statements of income. Capacity payments totaled $19 million, $27 million, and $50 million in 2014, 2013, and 2012, respectively. | ||||||||||||||||||||
The Company has also entered into various long-term PPAs, some of which are accounted for as capital or operating leases. Total capacity expense under PPAs accounted for as operating leases was $167 million, $162 million, and $169 million for 2014, 2013, and 2012, respectively. Estimated total long-term obligations at December 31, 2014 were as follows: | ||||||||||||||||||||
Affiliate Capital Leases | Affiliate Operating Leases | Non-Affiliate | Vogtle | Total ($) | ||||||||||||||||
Operating | Units 1 and 2 | |||||||||||||||||||
Leases (4) | Capacity | |||||||||||||||||||
Payments | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 22 | $ | 90 | $ | 114 | $ | 11 | $ | 237 | ||||||||||
2016 | 22 | 100 | 117 | 11 | 250 | |||||||||||||||
2017 | 23 | 71 | 146 | 10 | 250 | |||||||||||||||
2018 | 23 | 62 | 150 | 7 | 242 | |||||||||||||||
2019 | 23 | 63 | 152 | 6 | 244 | |||||||||||||||
2020 and thereafter | 255 | 606 | 1,572 | 50 | 2,483 | |||||||||||||||
Total | $ | 368 | $ | 992 | $ | 2,251 | $ | 95 | $ | 3,706 | ||||||||||
Less: amounts representing executory costs(1) | 55 | |||||||||||||||||||
Net minimum lease payments | 313 | |||||||||||||||||||
Less: amounts representing interest(2) | 85 | |||||||||||||||||||
Present value of net minimum lease payments(3) | $ | 228 | ||||||||||||||||||
-1 | Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments. | |||||||||||||||||||
-2 | Amount necessary to reduce minimum lease payments to present value calculated at the Company's incremental borrowing rate at the inception of the leases. | |||||||||||||||||||
-3 | Once service commences under the PPAs beginning in 2015, the Company will recognize capital lease assets and capital lease obligations totaling $149 million, being the lesser of the estimated fair value of the lease property or the present value of the net minimum lease payments. | |||||||||||||||||||
-4 | A total of $1.1 billion of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. | |||||||||||||||||||
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. | ||||||||||||||||||||
Operating Leases | ||||||||||||||||||||
In addition to the PPA operating leases discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $28 million for 2014, $32 million for 2013, and $34 million for 2012. The Company includes any step rents, fixed escalations, and lease concessions in its computation of minimum lease payments. | ||||||||||||||||||||
As of December 31, 2014, estimated minimum lease payments under operating leases were as follows: | ||||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Railcars | Other | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 18 | $ | 7 | $ | 25 | ||||||||||||||
2016 | 13 | 7 | 20 | |||||||||||||||||
2017 | 9 | 7 | 16 | |||||||||||||||||
2018 | 4 | 6 | 10 | |||||||||||||||||
2019 | 1 | 4 | 5 | |||||||||||||||||
2020 and thereafter | 3 | 11 | 14 | |||||||||||||||||
Total | $ | 48 | $ | 42 | $ | 90 | ||||||||||||||
Railcar minimum lease payments are disclosed at 100% of railcar lease obligations; however, a portion of these obligations is shared with the joint owners of Plants Scherer and Wansley. A majority of the rental expenses related to the railcar leases are recoverable through the fuel cost recovery clause as ordered by the Georgia PSC and the remaining portion is recovered through base rates. | ||||||||||||||||||||
In addition to the above rental commitments, the Company has obligations upon expiration of certain railcar leases with respect to the residual value of the leased property. These leases have terms expiring through 2024 with maximum obligations under these leases of $32 million. At the termination of the leases, the lessee may either renew the lease, exercise its purchase option, or the property can be sold to a third party. The Company expects that the fair market value of the leased property would substantially reduce or eliminate the Company's payments under the residual value obligations. | ||||||||||||||||||||
Guarantees | ||||||||||||||||||||
Alabama Power has guaranteed the obligations of SEGCO for $25 million of pollution control revenue bonds issued in 2001, which mature in June 2019 and also $100 million of senior notes issued in November 2013, which mature in December 2018. The Company has agreed to reimburse Alabama Power for the pro rata portion of such obligations corresponding to the Company's then proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. See Note 4 for additional information. | ||||||||||||||||||||
In addition, in December 2013, the Company entered into an agreement that requires the Company to guarantee certain payments of a gas supplier for Plant McIntosh for a period up to 15 years. The guarantee is expected to be terminated if certain events occur within one year of the initial gas deliveries in 2017. In the event the gas supplier defaults on payments, the maximum potential exposure under the guarantee is approximately $43 million. | ||||||||||||||||||||
As discussed earlier in this Note under "Operating Leases," the Company has entered into certain residual value guarantees related to railcar leases. | ||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
COMMITMENTS | COMMITMENTS | |||||||||||||||||||
Fuel and Purchased Power Agreements | ||||||||||||||||||||
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2014, 2013, and 2012, the Company incurred fuel expense of $604.6 million, $532.8 million, and $544.9 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. | ||||||||||||||||||||
In addition, the Company has entered into various long-term commitments for the purchase of capacity, energy, and transmission, some of which are accounted for as operating leases. The energy-related costs associated with PPAs are recovered through the fuel cost recovery clause. The capacity and transmission-related costs associated with PPAs are recovered through the purchased power capacity cost recovery clause. Capacity expense under purchased power agreements accounted for as operating leases was $49.5 million, $21.3 million, and $24.6 million for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||
Estimated total minimum long-term commitments at December 31, 2014 were as follows: | ||||||||||||||||||||
Operating Lease PPAs | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 78.7 | ||||||||||||||||||
2016 | 78.7 | |||||||||||||||||||
2017 | 78.8 | |||||||||||||||||||
2018 | 78.9 | |||||||||||||||||||
2019 | 78.9 | |||||||||||||||||||
2020 and thereafter | 270.3 | |||||||||||||||||||
Total | $ | 664.3 | ||||||||||||||||||
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. | ||||||||||||||||||||
Operating Leases | ||||||||||||||||||||
In addition to the operating lease PPAs discussed above, the Company has other operating lease agreements with various terms and expiration dates. Total rent expense was $15.0 million, $18.0 million, and $20.1 million for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||
Estimated total minimum lease payments under these operating leases at December 31, 2014 were as follows: | ||||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Barges & | Other | Total | ||||||||||||||||||
Railcars | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 15.1 | $ | 0.1 | $ | 15.2 | ||||||||||||||
2016 | 15 | 0.1 | 15.1 | |||||||||||||||||
2017 | 1.4 | 0.1 | 1.5 | |||||||||||||||||
Total | $ | 31.5 | $ | 0.3 | $ | 31.8 | ||||||||||||||
The Company and Mississippi Power jointly entered into an operating lease agreement for aluminum railcars for the transportation of coal to Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value or to renew the leases at the end of each lease term. The Company and Mississippi Power also have separate lease agreements for other railcars that do not include purchase options. The Company's share of the lease costs, charged to fuel inventory and recovered through the retail fuel cost recovery clause, was $2.8 million in 2014, $3.1 million in 2013, and $3.6 million in 2012. The Company's annual railcar lease payments for 2015 through 2017 will average approximately $1.6 million. The Company has no lease payment obligations for the period 2018 and thereafter. | ||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
COMMITMENTS | COMMITMENTS | |||||||||||||||||||
Fuel and Purchased Power Agreements | ||||||||||||||||||||
To supply a portion of the fuel requirements of its generating plants, the Company has entered into various long-term commitments for the procurement and delivery of fossil fuel which are not recognized on the balance sheets. In 2014, 2013, and 2012, the Company incurred fuel expense of $573.9 million, $491.3 million, and $411.2 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. | ||||||||||||||||||||
Coal commitments include a management fee associated with a 40-year management contract with Liberty Fuels related to the Kemper IGCC with the remaining amount as of December 31, 2014 of $38.4 million. Additional commitments for fuel will be required to supply the Company's future needs. | ||||||||||||||||||||
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and all of the other traditional operating companies and Southern Power. Under these agreements, each of the traditional operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with the Company and each of the other traditional operating companies to ensure the Company will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements. | ||||||||||||||||||||
Operating Leases | ||||||||||||||||||||
The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $12.7 million, $10.1 million, and $11.1 million for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||
The Company and Gulf Power have jointly entered into operating lease agreements for aluminum railcars for the transportation of coal at Plant Daniel. The Company has the option to purchase the railcars at the greater of lease termination value or fair market value, or to renew the leases at the end of the lease term. The Company has one remaining operating lease which has 229 aluminum railcars. The Company and Gulf Power also have separate lease agreements for other railcars that do not contain a purchase option. | ||||||||||||||||||||
The Company's share (50%) of the leases, charged to fuel stock and recovered through the fuel cost recovery clause, was $4.9 million in 2014, $3.1 million in 2013, and $3.6 million in 2012. The Company's annual railcar lease payments for 2015 through 2017 will average approximately $1.6 million. The Company has no lease obligations for the period 2018 and thereafter. | ||||||||||||||||||||
In addition to railcar leases, the Company has other operating leases for fuel handling equipment at Plants Daniel and Watson and operating leases for barges and tow/shift boats for the transport of coal at Plant Watson. The Company's share (50% at Plant Daniel and 100% at Plant Watson) of the leases for fuel handling was charged to fuel handling expense in the amount of $0.2 million annually from 2012 through 2014. The Company's annual lease payment for 2015 is expected to be $0.1 million for fuel handling equipment. The Company charged to fuel stock and recovered through fuel cost recovery the barge transportation leases in the amount of $7.5 million in 2014, $6.7 million in 2013, and $7.3 million in 2012 related to barges and tow/shift boats. The Company's annual lease payment for 2015 with respect to these barge transportation leases is expected to be $1.8 million. | ||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
COMMITMENTS | COMMITMENTS | |||||||||||||||||||
Fuel Agreements | ||||||||||||||||||||
SCS, as agent for the Company and the traditional operating companies, has entered into various fuel transportation and procurement agreements to supply a portion of the fuel (primarily natural gas) requirements for the operating facilities which are not recognized on the Company's balance sheets. In 2014, 2013, and 2012, the Company incurred fuel expense of $596.3 million, $473.8 million, and $426.3 million, respectively, the majority of which was purchased under long-term commitments. The Company expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. | ||||||||||||||||||||
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the Company and Southern Company's traditional operating companies. Under these agreements, each of the traditional operating companies and the Company may be jointly and severally liable. Southern Company has entered into keep-well agreements with each of the traditional operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of the Company as a contracting party under these agreements. | ||||||||||||||||||||
Operating Leases | ||||||||||||||||||||
The Company has operating lease agreements with various terms and expiration dates. Total rent expense was $4.0 million, $1.9 million, and $0.8 million for 2014, 2013, and 2012, respectively. These amounts include contingent rent expense related to the Plant Stanton Unit A land lease based on escalation in the Consumer Price Index for All Urban Consumers. The Company includes step rents, escalations, and lease concessions in its computation of minimum lease payments, which are recognized on a straight-line basis over the minimum lease term. As of December 31, 2014, estimated minimum lease payments under operating leases were $4.5 million in 2015, $4.5 million in 2016, $4.6 million in 2017, $4.6 million in 2018, $4.7 million in 2019, and $157.2 million in 2020 and thereafter. The majority of the committed future expenditures are land leases at solar facilities. | ||||||||||||||||||||
Redeemable Noncontrolling Interest | ||||||||||||||||||||
Pursuant to an agreement with TRE, on or after November 25, 2015, or earlier in the event of the death of the controlling member of TRE, TRE may require the Company to purchase its noncontrolling interest in STR at fair market value. | ||||||||||||||||||||
See Note 10 for additional information. |
Common_Stock_and_Stock_Compens
Common Stock and Stock Compensation | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Class of Stock [Line Items] | |||||||||
COMMON STOCK | COMMON STOCK | ||||||||
Stock Issued | |||||||||
During 2014, Southern Company issued approximately 20.8 million shares of common stock (including approximately 5.0 million treasury shares) for approximately $806 million through the employee and director stock plans and the Southern Investment Plan. The Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through the independent plan administrators. | |||||||||
From August 2013 through December 2014, Southern Company used shares held in treasury, to the extent available, and newly issued shares to satisfy the requirements under the Southern Investment Plan and the employee savings plan. Beginning in January 2015, Southern Company ceased issuing additional shares under the Southern Investment Plan and the employee savings plan. All sales under these plans are now being funded with shares acquired on the open market by the independent plan administrators. | |||||||||
Beginning in 2015, Southern Company expects to repurchase shares of common stock to offset all or a portion of the incremental shares issued under its employee and director stock plans, including through stock option exercises. The Southern Company Board of Directors has approved the repurchase of up to 20 million shares of common stock for such purpose until December 31, 2017. Repurchases may be made by means of open market purchases, privately negotiated transactions, or accelerated or other share repurchase programs, in accordance with applicable securities laws. | |||||||||
Shares Reserved | |||||||||
At December 31, 2014, a total of 93 million shares were reserved for issuance pursuant to the Southern Investment Plan, the Employee Savings Plan, the Outside Directors Stock Plan, and the Omnibus Incentive Compensation Plan (which includes stock options and performance shares units as discussed below). Of the total 93 million shares reserved, there were 15 million shares of common stock remaining available for awards under the Omnibus Incentive Compensation Plan as of December 31, 2014. | |||||||||
Stock Options | |||||||||
Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. As of December 31, 2014, there were 5,437 current and former employees participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. Southern Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
The estimated fair values of stock options granted were derived using the Black-Scholes stock option pricing model. Expected volatility was based on historical volatility of Southern Company's stock over a period equal to the expected term. Southern Company used historical exercise data to estimate the expected term that represents the period of time that options granted to employees are expected to be outstanding. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the expected term of the stock options. | |||||||||
The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: | |||||||||
Year Ended December 31 | 2014 | 2013 | 2012 | ||||||
Expected volatility | 14.60% | 16.60% | 17.70% | ||||||
Expected term (in years) | 5 | 5 | 5 | ||||||
Interest rate | 1.50% | 0.90% | 0.90% | ||||||
Dividend yield | 4.90% | 4.40% | 4.20% | ||||||
Weighted average grant-date fair value | $2.20 | $2.93 | $3.39 | ||||||
Southern Company's activity in the stock option program for 2014 is summarized below: | |||||||||
Shares Subject to Option | Weighted Average Exercise Price | ||||||||
Outstanding at December 31, 2013 | 38,819,366 | $38.64 | |||||||
Granted | 12,812,691 | 41.4 | |||||||
Exercised | 11,585,363 | 35.06 | |||||||
Cancelled | 117,375 | 42.72 | |||||||
Outstanding at December 31, 2014 | 39,929,319 | $40.55 | |||||||
Exercisable at December 31, 2014 | 20,695,310 | $38.76 | |||||||
The number of stock options vested, and expected to vest in the future, as of December 31, 2014 was not significantly different from the number of stock options outstanding at December 31, 2014 as stated above. As of December 31, 2014, the weighted average remaining contractual term for the options outstanding and options exercisable was approximately seven years and six years, respectively, and the aggregate intrinsic value for the options outstanding and options exercisable was $342 million and $214 million, respectively. | |||||||||
As of December 31, 2014, there was $10 million of total unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 16 months. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, total compensation cost for stock option awards recognized in income was $27 million, $25 million, and $23 million, respectively, with the related tax benefit also recognized in income of $10 million, $10 million, and $9 million, respectively. | |||||||||
The total intrinsic value of options exercised during the years ended December 31, 2014, 2013, and 2012 was $125 million, $77 million, and $162 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $48 million, $30 million, and $62 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||||||
Southern Company has a policy of issuing shares to satisfy share option exercises. Cash received from issuances related to option exercises under the share-based payment arrangements for the years ended December 31, 2014, 2013, and 2012 was $400 million, $204 million, and $397 million, respectively. | |||||||||
Performance Shares | |||||||||
Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of Southern Company system employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount. Performance share units held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
The fair value of performance share awards is determined as of the grant date using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period. Southern Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. The expected volatility was based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate was based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the award units. | |||||||||
The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted: | |||||||||
Year Ended December 31 | 2014 | 2013 | 2012 | ||||||
Expected volatility | 12.60% | 12.00% | 16.00% | ||||||
Expected term (in years) | 3 | 3 | 3 | ||||||
Interest rate | 0.60% | 0.40% | 0.40% | ||||||
Annualized dividend rate | $2.03 | $1.96 | $1.89 | ||||||
Weighted average grant-date fair value | $37.54 | $40.50 | $41.99 | ||||||
Total unvested performance share units outstanding as of December 31, 2013 were 1,643,759. During 2014, 1,057,813 performance share units were granted, 755,716 performance share units were vested, and 115,475 performance share units were forfeited, resulting in 1,830,381 unvested units outstanding at December 31, 2014. In January 2015, the vested performance share award units were converted into 105,783 shares outstanding at a share price of $49.71 for the three-year performance and vesting period ended December 31, 2014. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, total compensation cost for performance share units recognized in income was $33 million, $31 million, and $28 million, respectively, with the related tax benefit also recognized in income of $13 million, $12 million, and $11 million, respectively. As of December 31, 2014, there was $37 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 20 months. | |||||||||
Diluted Earnings Per Share | |||||||||
For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under the stock option and performance share plans. The effect of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows: | |||||||||
Average Common Stock Shares | |||||||||
2014 | 2013 | 2012 | |||||||
(in millions) | |||||||||
As reported shares | 897 | 877 | 871 | ||||||
Effect of options and performance share award units | 4 | 4 | 8 | ||||||
Diluted shares | 901 | 881 | 879 | ||||||
Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were $7 million and $16 million as of December 31, 2014 and 2013, respectively. | |||||||||
Common Stock Dividend Restrictions | |||||||||
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2014, consolidated retained earnings included $6.4 billion of undistributed retained earnings of the subsidiaries. | |||||||||
Alabama Power [Member] | |||||||||
Class of Stock [Line Items] | |||||||||
STOCK COMPENSATION | STOCK COMPENSATION | ||||||||
Stock Options | |||||||||
Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2014, there were approximately 1,000 current and former employees of the Company participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted stock options for 2,027,298 shares, 1,319,038 shares, and 1,099,315 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014, 2013, and 2012, derived using the Black-Scholes stock option pricing model, was $2.20, $2.93, and $3.39, respectively. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, total compensation cost for stock option awards recognized in income was $5 million, $4 million, and $4 million, respectively, with the related tax benefit also recognized in income of $2 million, $2 million, and $1 million, respectively. The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. As of December 31, 2014, there was $1 million of unrecognized compensation cost related to stock option awards not yet vested. That cost is expected to be recognized over a weighted-average period of approximately 15 months. | |||||||||
The total intrinsic value of options exercised during the years ended December 31, 2014, 2013, and 2012 was $21 million, $11 million, and $28 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $8 million, $4 million, and $11 million for the years ended December 31, 2014, 2013, and 2012, respectively. As of December 31, 2014, the aggregate intrinsic value for the options outstanding and options exercisable was $55 million and $37 million, respectively. | |||||||||
Performance Shares | |||||||||
Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount. Performance share units held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted performance share units of 176,070, 141,355, and 131,820, respectively. The weighted average grant-date fair value of performance share units granted during 2014, 2013, and 2012, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $37.54, $40.50, and $41.99, respectively. | |||||||||
The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. For the years ended December 31, 2014, 2013, and 2012, total compensation cost for performance share units recognized in income was $5 million annually, with the related tax benefit of $2 million annually also recognized in income. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2014, there was $5 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 20 months. | |||||||||
Georgia Power [Member] | |||||||||
Class of Stock [Line Items] | |||||||||
STOCK COMPENSATION | STOCK COMPENSATION | ||||||||
Stock Options | |||||||||
Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2014, there were approximately 1,000 current and former employees of the Company participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted stock options for 2,034,150 shares, 1,509,662 shares, and 1,269,725 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014, 2013, and 2012, derived using the Black-Scholes stock option pricing model, was $2.20, $2.93, and $3.39, respectively. | |||||||||
The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. | |||||||||
As of December 31, 2014, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. | |||||||||
The total intrinsic value of options exercised during the years ended December 31, 2014, 2013, and 2012 was $19 million, $16 million, and $34 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $7 million, $6 million, and $13 million for the years ended December 31, 2014, 2013, and 2012, respectively. As of December 31, 2014, the aggregate intrinsic value for the options outstanding and options exercisable was $73 million and $51 million, respectively. | |||||||||
Performance Shares | |||||||||
Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount. Performance share units held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted performance share units of 176,224, 161,240, and 152,812, respectively. The weighted average grant-date fair value of performance share units granted during 2014, 2013, and 2012, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $37.54, $40.50, and $41.99, respectively. | |||||||||
The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. For the years ended December 31, 2014, 2013, and 2012, total compensation cost for performance share units recognized in income was $6 million annually, with the related tax benefit of $2 million annually also recognized in income. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2014, there was $7 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 20 months. | |||||||||
Gulf Power [Member] | |||||||||
Class of Stock [Line Items] | |||||||||
STOCK COMPENSATION | STOCK COMPENSATION | ||||||||
Stock Options | |||||||||
Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. As of December 31, 2014, there were 195 current and former employees of the Company participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted stock options for 432,371 shares, 285,209 shares, and 244,607 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014, 2013, and 2012, derived using the Black-Scholes stock option pricing model, was $2.20, $2.93, and $3.39, respectively. | |||||||||
The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. | |||||||||
As of December 31, 2014, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. | |||||||||
The total intrinsic value of options exercised during the years ended December 31, 2014, 2013, and 2012 was $5.2 million, $1.7 million, and $3.8 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $2.0 million, $0.6 million, and $1.5 million for the years ended December 31, 2014, 2013, and 2012, respectively. As of December 31, 2014, the aggregate intrinsic value for the options outstanding and options exercisable was $11.9 million and $7.7 million, respectively. | |||||||||
Performance Shares | |||||||||
Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount. Performance share units held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted performance share units of 37,829, 30,627, and 29,444, respectively. The weighted average grant-date fair value of performance share units granted during 2014, 2013, and 2012, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $37.54, $40.50, and $41.99, respectively. | |||||||||
The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. For the years ended December 31, 2014, 2013, and 2012, total compensation cost for performance share units recognized in income was approximately $1.0 million annually, with the related tax benefit also recognized in income of $0.4 million annually. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2014, there was $1.3 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 20 months. | |||||||||
Mississippi Power [Member] | |||||||||
Class of Stock [Line Items] | |||||||||
STOCK COMPENSATION | STOCK COMPENSATION | ||||||||
Stock Options | |||||||||
Southern Company provides non-qualified stock options through its Omnibus Incentive Compensation Plan to a large segment of the Company's system employees ranging from line management to executives. As of December 31, 2014, there were 244 current and former employees of the Company participating in the stock option program. The prices of options were at the fair market value of the shares on the dates of grant. These options become exercisable pro rata over a maximum period of three years from the date of grant. The Company generally recognizes stock option expense on a straight-line basis over the vesting period which equates to the requisite service period; however, for employees who are eligible for retirement, the total cost is expensed at the grant date. Options outstanding will expire no later than 10 years after the date of grant, unless terminated earlier by the Southern Company Board of Directors in accordance with the Omnibus Incentive Compensation Plan. Stock options held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted stock options for 578,256 shares, 345,830 shares, and 278,709 shares, respectively. The weighted average grant-date fair value of stock options granted during 2014, 2013, and 2012, derived using the Black-Scholes stock option pricing model, was $2.20, $2.93, and $3.39, respectively. | |||||||||
The compensation cost and tax benefits related to the grant of Southern Company stock options to the Company's employees and the exercise of stock options are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. No cash proceeds are received by the Company upon the exercise of stock options. The amounts were not material for any year presented. | |||||||||
As of December 31, 2014, the amount of unrecognized compensation cost related to stock option awards not yet vested was immaterial. | |||||||||
The total intrinsic value of options exercised during the years ended December 31, 2014, 2013, and 2012 was $5.4 million, $2.7 million, and $4.9 million, respectively. The actual tax benefit realized by the Company for the tax deductions from stock option exercises totaled $2.1 million, $1.1 million, and $1.9 million for the years ended December 31, 2014, 2013, and 2012, respectively. As of December 31, 2014, the aggregate intrinsic value for the options outstanding and options exercisable was $18.4 million and $12.3 million, respectively. | |||||||||
Performance Shares | |||||||||
Southern Company provides performance share award units through its Omnibus Incentive Compensation Plan to a large segment of the Company's employees ranging from line management to executives. The performance share units granted under the plan vest at the end of a three-year performance period which equates to the requisite service period. Employees that retire prior to the end of the three-year period receive a pro rata number of shares, issued at the end of the performance period, based on actual months of service prior to retirement. The value of the award units is based on Southern Company's total shareholder return (TSR) over the three-year performance period which measures Southern Company's relative performance against a group of industry peers. The performance shares are delivered in common stock following the end of the performance period based on Southern Company's actual TSR and may range from 0% to 200% of the original target performance share amount. Performance share units held by employees of a company undergoing a change in control vest upon the change in control. | |||||||||
For the years ended December 31, 2014, 2013, and 2012, employees of the Company were granted performance share units of 49,579, 36,769, and 33,077, respectively. The weighted average grant-date fair value of performance share units granted during 2014, 2013, and 2012, determined using a Monte Carlo simulation model to estimate the TSR of Southern Company's stock among the industry peers over the performance period, was $37.54, $40.50, and $41.99, respectively. | |||||||||
The Company recognizes compensation expense on a straight-line basis over the three-year performance period without remeasurement. Compensation expense for awards where the service condition is met is recognized regardless of the actual number of shares issued. For the years ended December 31, 2014, 2013, and 2012, total compensation cost for performance share units recognized in income was $1.7 million, $1.5 million, and $1.2 million, respectively, with the related tax benefit also recognized in income of $0.6 million, $0.6 million, and $0.4 million, respectively. The compensation cost and tax benefits related to the grant of Southern Company performance share units to the Company's employees are recognized in the Company's financial statements with a corresponding credit to equity, representing a capital contribution from Southern Company. As of December 31, 2014, there was $1.8 million of total unrecognized compensation cost related to performance share award units that will be recognized over a weighted-average period of approximately 20 months. |
Nuclear_Insurance
Nuclear Insurance | 12 Months Ended |
Dec. 31, 2014 | |
Nuclear Insurance [Line Items] | |
NUCLEAR INSURANCE | NUCLEAR INSURANCE |
Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $255 million and $247 million, respectively, per incident, but not more than an aggregate of $38 million and $37 million, respectively, per company to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 herein for additional information on joint ownership agreements. | |
Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. | |
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. | |
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction. | |
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for Alabama Power and Georgia Power under the NEIL policies would be $50 million and $72 million, respectively. | |
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. | |
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's financial condition and results of operations. | |
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. | |
Alabama Power [Member] | |
Nuclear Insurance [Line Items] | |
NUCLEAR INSURANCE | NUCLEAR INSURANCE |
Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Farley. The Act provides funds up to $13.6 billion for public liability claims that could arise from a single nuclear incident. Plant Farley is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company is $255 million per incident but not more than an aggregate of $38 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. | |
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. | |
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases limits based on the projected full cost of replacement power and has elected a 12-week deductible waiting period. | |
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $50 million. | |
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. | |
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by the Company and could have a material effect on the Company's financial condition and results of operations. | |
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. | |
Georgia Power [Member] | |
Nuclear Insurance [Line Items] | |
NUCLEAR INSURANCE | NUCLEAR INSURANCE |
Under the Price-Anderson Amendments Act (Act), the Company maintains agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at Plant Hatch and Plant Vogtle Units 1 and 2. The Act provides funds up to $13.6 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $375 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. The Company could be assessed up to $127 million per incident for each licensed reactor it operates but not more than an aggregate of $19 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for the Company, based on its ownership and buyback interests in all licensed reactors, is $247 million, per incident, but not more than an aggregate of $37 million to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than September 10, 2018. See Note 4 for additional information on joint ownership agreements. | |
The Company is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, the Company has NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses in excess of the $1.5 billion primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. | |
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted in approximately three years. The Company purchases limits based on the projected full cost of replacement power, subject to ownership limitations. Each facility has elected a 12-week deductible waiting period. | |
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Owners up to $2.75 billion for accidental property damage occurring during construction. | |
Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The current maximum annual assessments for the Company under the NEIL policies would be $72 million. | |
Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. | |
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the Company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by the Company and could have a material effect on the Company's financial condition and results of operations. | |
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes. |
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS | |||||||||||||||
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. | ||||||||||||||||
• | Level 1 consists of observable market data in an active market for identical assets or liabilities. | |||||||||||||||
• | Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. | |||||||||||||||
• | Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. | |||||||||||||||
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. | ||||||||||||||||
As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 13 | $ | — | $ | 13 | ||||||||
Interest rate derivatives | — | 8 | — | 8 | ||||||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 583 | 85 | — | 668 | ||||||||||||
Foreign equity | 34 | 184 | — | 218 | ||||||||||||
U.S. Treasury and government agency securities | — | 130 | — | 130 | ||||||||||||
Municipal bonds | — | 62 | — | 62 | ||||||||||||
Corporate bonds | — | 299 | — | 299 | ||||||||||||
Mortgage and asset backed securities | — | 139 | — | 139 | ||||||||||||
Other | 11 | 13 | 3 | 27 | ||||||||||||
Cash equivalents | 397 | — | — | 397 | ||||||||||||
Other investments | 9 | — | 1 | 10 | ||||||||||||
Total | $ | 1,034 | $ | 933 | $ | 4 | $ | 1,971 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 201 | $ | — | $ | 201 | ||||||||
Interest rate derivatives | — | 24 | — | 24 | ||||||||||||
Total | $ | — | $ | 225 | $ | — | $ | 225 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 24 | $ | — | $ | 24 | ||||||||
Interest rate derivatives | — | 3 | — | 3 | ||||||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 589 | 75 | — | 664 | ||||||||||||
Foreign equity | 35 | 196 | — | 231 | ||||||||||||
U.S. Treasury and government agency securities | — | 103 | — | 103 | ||||||||||||
Municipal bonds | — | 64 | — | 64 | ||||||||||||
Corporate bonds | — | 229 | — | 229 | ||||||||||||
Mortgage and asset backed securities | — | 132 | — | 132 | ||||||||||||
Other | — | 37 | 3 | 40 | ||||||||||||
Cash equivalents | 491 | — | — | 491 | ||||||||||||
Other investments | 9 | — | 4 | 13 | ||||||||||||
Total | $ | 1,124 | $ | 863 | $ | 7 | $ | 1,994 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 56 | $ | — | $ | 56 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
Valuation Methodologies | ||||||||||||||||
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note 11 for additional information on how these derivatives are used. | ||||||||||||||||
For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. | ||||||||||||||||
A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgment, are also obtained when available. | ||||||||||||||||
Investments in private equity and real estate within the nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. | ||||||||||||||||
"Other investments" include investments that are not traded in the open market. The fair value of these investment have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions. | ||||||||||||||||
As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | ||||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity funds | $ | 121 | None | Monthly | 5 days | |||||||||||
Equity – commingled funds | 63 | None | Daily/Monthly | Daily/7 days | ||||||||||||
Debt – commingled funds | 15 | None | Daily | 5 days | ||||||||||||
Other – commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Other – money market funds | 11 | None | Daily | Not applicable | ||||||||||||
Trust-owned life insurance | 115 | None | Daily | 15 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 397 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity funds | $ | 131 | None | Monthly | 5 days | |||||||||||
Corporate bonds – commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Equity – commingled funds | 65 | None | Daily/Monthly | Daily/7 days | ||||||||||||
Other – commingled funds | 24 | None | Daily | Not applicable | ||||||||||||
Trust-owned life insurance | 110 | None | Daily | 15 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 491 | None | Daily | Not applicable | ||||||||||||
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have the Funds to comply with the NRC's regulations. The foreign equity fund in Georgia Power's nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts, including American depositary receipts, European depositary receipts, and global depositary receipts; and rights and warrants to buy common stocks. Georgia Power may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date. | ||||||||||||||||
The other-commingled funds and other-money market funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio of high quality, short-term, liquid debt securities. The funds represent the cash collateral received under the Funds' managers' securities lending program and/or the excess cash held within each separate investment account. The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the funds. See Note 1 under "Nuclear Decommissioning" for additional information. | ||||||||||||||||
Alabama Power's nuclear decommissioning trusts include investments in TOLI. The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in Alabama Power's nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. See Note 1 under "Nuclear Decommissioning" for additional information. | ||||||||||||||||
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds. | ||||||||||||||||
As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | ||||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 24,015 | $ | 25,816 | ||||||||||||
2013 | $ | 21,650 | $ | 22,197 | ||||||||||||
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power. | ||||||||||||||||
Alabama Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS | |||||||||||||||
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. | ||||||||||||||||
• | Level 1 consists of observable market data in an active market for identical assets or liabilities. | |||||||||||||||
• | Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. | |||||||||||||||
• | Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. | |||||||||||||||
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. | ||||||||||||||||
As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 1 | $ | — | $ | 1 | ||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 403 | 83 | — | 486 | ||||||||||||
Foreign equity | 34 | 63 | — | 97 | ||||||||||||
U.S. Treasury and government agency securities | — | 34 | — | 34 | ||||||||||||
Corporate bonds | — | 111 | — | 111 | ||||||||||||
Mortgage and asset backed securities | — | 18 | — | 18 | ||||||||||||
Other | — | 5 | 3 | 8 | ||||||||||||
Cash equivalents | 162 | — | — | 162 | ||||||||||||
Total | $ | 599 | $ | 315 | $ | 3 | $ | 917 | ||||||||
Liabilities: | ||||||||||||||||
Interest rate derivatives | $ | — | $ | 8 | $ | — | $ | 8 | ||||||||
Energy-related derivatives | — | 53 | — | 53 | ||||||||||||
Total | $ | — | $ | 61 | $ | — | $ | 61 | ||||||||
(a) | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 7 | $ | — | $ | 7 | ||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 392 | 74 | — | 466 | ||||||||||||
Foreign equity | 35 | 65 | — | 100 | ||||||||||||
U.S. Treasury and government agency securities | — | 24 | — | 24 | ||||||||||||
Corporate bonds | — | 89 | — | 89 | ||||||||||||
Mortgage and asset backed securities | — | 18 | — | 18 | ||||||||||||
Other | — | 13 | 3 | 16 | ||||||||||||
Cash equivalents | 236 | — | — | 236 | ||||||||||||
Total | $ | 663 | $ | 290 | $ | 3 | $ | 956 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 8 | $ | — | $ | 8 | ||||||||
(a) | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. | |||||||||||||||
Valuation Methodologies | ||||||||||||||||
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note 11 for additional information on how these derivatives are used. | ||||||||||||||||
For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. | ||||||||||||||||
A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgment, are also obtained when available. | ||||||||||||||||
Investments in private equity and real estate within the nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets. | ||||||||||||||||
As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | ||||||||||||||||
Fair | Unfunded | Redemption Frequency | Redemption | |||||||||||||
Value | Commitments | Notice Period | ||||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Equity – commingled funds | $ | 63 | None | Daily/Monthly | Daily/7 days | |||||||||||
Trust – owned life insurance | 115 | None | Daily | 15 days | ||||||||||||
Debt – commingled funds | 15 | None | Daily | 5 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 162 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Equity – commingled funds | $ | 65 | None | Daily/Monthly | Daily/7 days | |||||||||||
Trust – owned life insurance | 110 | None | Daily | 15 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 236 | None | Daily | Not applicable | ||||||||||||
The nuclear decommissioning trusts include investments in TOLI. The taxable nuclear decommissioning trusts invest in the TOLI in order to minimize the impact of taxes on the portfolios and can draw on the value of the TOLI through death proceeds, loans against the cash surrender value, and/or the cash surrender value, subject to legal restrictions. The amounts reported in the table above reflect the fair value of investments the insurer has made in relation to the TOLI agreements. The nuclear decommissioning trusts do not own the underlying investments, but the fair value of the investments approximates the cash surrender value of the TOLI policies. The investments made by the insurer are in commingled funds. These commingled funds, along with other equity and debt commingled funds held in the nuclear decommissioning trusts, primarily include investments in domestic and international equity securities and predominantly high-quality fixed income securities. These fixed income securities may include U.S. Treasury and government agency fixed income securities, non-U.S. government and agency fixed income securities, domestic and foreign corporate fixed income securities, and mortgage and asset backed securities. The passively managed funds seek to replicate the performance of a related index. The actively managed funds seek to exceed the performance of a related index through security analysis and selection. | ||||||||||||||||
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds. | ||||||||||||||||
As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | ||||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 6,631 | $ | 7,321 | ||||||||||||
2013 | $ | 6,228 | $ | 6,534 | ||||||||||||
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company. | ||||||||||||||||
Georgia Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS | |||||||||||||||
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. | ||||||||||||||||
• | Level 1 consists of observable market data in an active market for identical assets or liabilities. | |||||||||||||||
• | Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. | |||||||||||||||
• | Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. | |||||||||||||||
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. | ||||||||||||||||
As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 7 | $ | — | $ | 7 | ||||||||
Interest rate derivatives | — | 6 | — | 6 | ||||||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 180 | 2 | — | 182 | ||||||||||||
Foreign equity | — | 121 | — | 121 | ||||||||||||
U.S. Treasury and government agency securities | — | 96 | — | 96 | ||||||||||||
Municipal bonds | — | 62 | — | 62 | ||||||||||||
Corporate bonds | — | 188 | — | 188 | ||||||||||||
Mortgage and asset backed securities | — | 121 | — | 121 | ||||||||||||
Other | 11 | 8 | — | 19 | ||||||||||||
Total | $ | 191 | $ | 611 | $ | — | $ | 802 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 27 | $ | — | $ | 27 | ||||||||
Interest rate derivatives | — | 14 | — | 14 | ||||||||||||
Total | $ | — | $ | 41 | $ | — | $ | 41 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 5 | $ | — | $ | 5 | ||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 197 | 1 | — | 198 | ||||||||||||
Foreign equity | — | 131 | — | 131 | ||||||||||||
U.S. Treasury and government agency securities | — | 79 | — | 79 | ||||||||||||
Municipal bonds | — | 64 | — | 64 | ||||||||||||
Corporate bonds | — | 140 | — | 140 | ||||||||||||
Mortgage and asset backed securities | — | 114 | — | 114 | ||||||||||||
Other | — | 24 | — | 24 | ||||||||||||
Total | $ | 197 | $ | 558 | $ | — | $ | 755 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 21 | $ | — | $ | 21 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
Valuation Methodologies | ||||||||||||||||
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally, implied volatility of interest rate options. See Note 11 for additional information on how these derivatives are used. | ||||||||||||||||
For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgment, are also obtained when available. | ||||||||||||||||
As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | ||||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity fund | $ | 121 | None | Monthly | 5 days | |||||||||||
Other — commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Other — money market funds | 11 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity fund | $ | 131 | None | Daily | 5 days | |||||||||||
Corporate bonds — commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Other — commingled funds | 24 | None | Daily | Not applicable | ||||||||||||
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The foreign equity fund in the nuclear decommissioning trusts seeks to provide long-term capital appreciation. In pursuing this investment objective, the foreign equity fund primarily invests in a diversified portfolio of equity securities of foreign companies, including those in emerging markets. These equity securities may include, but are not limited to, common stocks, preferred stocks, real estate investment trusts, convertible securities, depositary receipts, including American depositary receipts, European depositary receipts, and global depositary receipts; and rights and warrants to buy common stocks. The Company may withdraw all or a portion of its investment on the last business day of each month subject to a minimum withdrawal of $1 million, provided that a minimum investment of $10 million remains. If notices of withdrawal exceed 20% of the aggregate value of the foreign equity fund, then the foreign equity fund's board may refuse to permit the withdrawal of all such investments and may scale down the amounts to be withdrawn pro rata and may further determine that any withdrawal that has been postponed will have priority on the subsequent withdrawal date. | ||||||||||||||||
The other-commingled funds and other-money market funds in the nuclear decommissioning trusts are invested primarily in a diversified portfolio of high quality, short-term, liquid debt securities. The funds represent the cash collateral received under the Funds' managers' securities lending program and/or the excess cash held within each separate investment account. The primary objective of the funds is to provide a high level of current income consistent with stability of principal and liquidity. The funds invest primarily in, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government or its agencies or instrumentalities, time deposits, repurchase agreements, municipal obligations, notes, and other high-quality short-term liquid debt securities that mature in 90 days or less. Redemptions are available on a same day basis up to the full amount of the investment in the funds. See Note 1 under "Nuclear Decommissioning" for additional information. | ||||||||||||||||
As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | ||||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 9,797 | $ | 10,552 | ||||||||||||
2013 | $ | 8,593 | $ | 8,782 | ||||||||||||
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on current rates offered to the Company. | ||||||||||||||||
Gulf Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS | |||||||||||||||
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. | ||||||||||||||||
• | Level 1 consists of observable market data in an active market for identical assets or liabilities. | |||||||||||||||
• | Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. | |||||||||||||||
• | Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. | |||||||||||||||
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. | ||||||||||||||||
As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 125 | $ | — | $ | 125 | ||||||||
Cash equivalents | 18,032 | — | — | 18,032 | ||||||||||||
Total | $ | 18,032 | $ | 125 | $ | — | $ | 18,157 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 72,435 | $ | — | $ | 72,435 | ||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 6,962 | $ | — | $ | 6,962 | ||||||||
Cash equivalents | 15,929 | — | — | 15,929 | ||||||||||||
Total | $ | 15,929 | $ | 6,962 | $ | — | $ | 22,891 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 17,043 | $ | — | $ | 17,043 | ||||||||
Valuation Methodologies | ||||||||||||||||
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. See Note 10 for additional information on how these derivatives are used. | ||||||||||||||||
As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | ||||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in thousands) | |||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $18,032 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $15,929 | None | Daily | Not applicable | ||||||||||||
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds. | ||||||||||||||||
As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | ||||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in thousands) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 1,369,594 | $ | 1,476,954 | ||||||||||||
2013 | $ | 1,233,163 | $ | 1,261,889 | ||||||||||||
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company. | ||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS | |||||||||||||||
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. | ||||||||||||||||
• | Level 1 consists of observable market data in an active market for identical assets or liabilities. | |||||||||||||||
• | Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. | |||||||||||||||
• | Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. | |||||||||||||||
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. | ||||||||||||||||
As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 65 | $ | — | $ | 65 | ||||||||
Cash equivalents | 114,900 | — | — | 114,900 | ||||||||||||
Total | $ | 114,900 | $ | 65 | $ | — | $ | 114,965 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 45,429 | $ | — | $ | 45,429 | ||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 4,803 | $ | — | $ | 4,803 | ||||||||
Cash equivalents | 125,000 | — | — | 125,000 | ||||||||||||
Total | $ | 125,000 | $ | 4,803 | $ | — | $ | 129,803 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 10,281 | $ | — | $ | 10,281 | ||||||||
Foreign currency derivatives | — | 1 | — | 1 | ||||||||||||
Total | $ | — | $ | 10,282 | $ | — | $ | 10,282 | ||||||||
Valuation Methodologies | ||||||||||||||||
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for foreign currency derivatives are from observable market sources. See Note 10 for additional information on how these derivatives are used. | ||||||||||||||||
As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | ||||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in thousands) | |||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 114,900 | None | Daily | Not applicable | |||||||||||
As of December 31, 2013: | ||||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 125,000 | None | Daily | Not applicable | |||||||||||
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds. | ||||||||||||||||
As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | ||||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in thousands) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 2,328,476 | $ | 2,382,050 | ||||||||||||
2013 | $ | 2,098,639 | $ | 2,045,519 | ||||||||||||
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company. | ||||||||||||||||
Southern Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS | |||||||||||||||
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. | ||||||||||||||||
• | Level 1 consists of observable market data in an active market for identical assets or liabilities. | |||||||||||||||
• | Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable. | |||||||||||||||
• | Level 3 consists of unobservable market data. The input may reflect the assumptions of the Company of what a market participant would use in pricing an asset or liability. If there is little available market data, then the Company's own assumptions are the best available information. | |||||||||||||||
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported. | ||||||||||||||||
As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 5.5 | $ | — | $ | 5.5 | ||||||||
Cash equivalents | 18 | — | — | 18 | ||||||||||||
Total | $ | 18 | $ | 5.5 | $ | — | $ | 23.5 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 3.6 | $ | — | $ | 3.6 | ||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 0.6 | $ | — | $ | 0.6 | ||||||||
Cash equivalents | 68 | — | — | 68 | ||||||||||||
Total | $ | 68 | $ | 0.6 | $ | — | $ | 68.6 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 0.6 | $ | — | $ | 0.6 | ||||||||
Valuation Methodologies | ||||||||||||||||
The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. See Note 9 for additional information on how these derivatives are used. | ||||||||||||||||
As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | ||||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 18 | None | Daily | Not applicable | |||||||||||
As of December 31, 2013: | ||||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 68 | None | Daily | Not applicable | |||||||||||
The money market funds are short-term investments of excess funds in various money market mutual funds, which are portfolios of short-term debt securities. The money market funds are regulated by the SEC and typically receive the highest rating from credit rating agencies. Regulatory and rating agency requirements for money market funds include minimum credit ratings and maximum maturities for individual securities and a maximum weighted average portfolio maturity. Redemptions are available on a same day basis up to the full amount of the Company's investment in the money market funds. | ||||||||||||||||
As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | ||||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt, including securities due within one year: | ||||||||||||||||
2014 | $ | 1,621 | $ | 1,785 | ||||||||||||
2013 | $ | 1,620 | $ | 1,660 | ||||||||||||
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates offered to the Company. |
Derivatives
Derivatives | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
DERIVATIVES | DERIVATIVES | |||||||||||||||||||||||
Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities. | ||||||||||||||||||||||||
Energy-Related Derivatives | ||||||||||||||||||||||||
The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales from its uncontracted generating capacity. Further, the traditional operating companies may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity. | ||||||||||||||||||||||||
To mitigate residual risks relative to movements in electricity prices, the traditional operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the traditional operating companies and Southern Power may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. | ||||||||||||||||||||||||
Energy-related derivative contracts are accounted for in one of three methods: | ||||||||||||||||||||||||
• | Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. | |||||||||||||||||||||||
• | Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. | |||||||||||||||||||||||
• | Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. | |||||||||||||||||||||||
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. | ||||||||||||||||||||||||
At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions totaled 244 million mmBtu for the Southern Company system, with the longest hedge date of 2019 over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date of 2017 for derivatives not designated as hedges. | ||||||||||||||||||||||||
In addition to the volumes discussed above, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 6 million mmBtu. | ||||||||||||||||||||||||
For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2015 are immaterial for Southern Company. | ||||||||||||||||||||||||
Interest Rate Derivatives | ||||||||||||||||||||||||
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. | ||||||||||||||||||||||||
At December 31, 2014, the following interest rate derivatives were outstanding: | ||||||||||||||||||||||||
Notional | Interest | Weighted Average Interest | Hedge | Fair Value | ||||||||||||||||||||
Amount | Rate | Rate Paid | Maturity | Gain (Loss) | ||||||||||||||||||||
Received | Date | December 31, | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Cash Flow Hedges of Forecasted Debt | ||||||||||||||||||||||||
$200 | 3-month LIBOR | 2.93% | Oct-25 | $ | (8 | ) | ||||||||||||||||||
350 | 3-month LIBOR | 2.57% | May-25 | (6 | ) | |||||||||||||||||||
350 | 3-month LIBOR | 2.57% | Nov-25 | (2 | ) | |||||||||||||||||||
Cash Flow Hedges of Existing Debt | ||||||||||||||||||||||||
250 | 3-month LIBOR + 0.32% | 0.75% | Mar-16 | — | ||||||||||||||||||||
200 | 3-month LIBOR + 0.40% | 1.01% | Aug-16 | — | ||||||||||||||||||||
Fair Value Hedges of Existing Debt | ||||||||||||||||||||||||
250 | 1.30% | 3-month LIBOR + 0.17% | Aug-17 | 1 | ||||||||||||||||||||
250 | 5.40% | 3-month LIBOR + 4.02% | Jun-18 | (1 | ) | |||||||||||||||||||
200 | 4.25% | 3-month LIBOR + 2.46% | Dec-19 | — | ||||||||||||||||||||
Total | $2,050 | $ | (16 | ) | ||||||||||||||||||||
The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending December 31, 2015 are immaterial. The Company has deferred gains and losses that are expected to be amortized into earnings through 2037. | ||||||||||||||||||||||||
Foreign Currency Derivatives | ||||||||||||||||||||||||
Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. At December 31, 2014, there were no foreign currency derivatives outstanding. | ||||||||||||||||||||||||
Derivative Financial Statement Presentation and Amounts | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 7 | $ | 16 | Other current liabilities | $ | 118 | $ | 26 | ||||||||||||||
Other deferred charges and assets | — | 7 | Other deferred credits and liabilities | 79 | 29 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 7 | $ | 23 | $ | 197 | $ | 55 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||||||||||||
Interest rate derivatives: | Other current assets | $ | 7 | $ | 3 | Other current liabilities | $ | 17 | $ | — | ||||||||||||||
Other deferred charges and assets | 1 | — | Other deferred credits and liabilities | 7 | — | |||||||||||||||||||
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 8 | $ | 3 | $ | 24 | $ | — | ||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Energy-related derivatives | Other current assets | $ | 6 | $ | — | Other current liabilities | $ | 4 | $ | 1 | ||||||||||||||
Other deferred charges and assets | — | 1 | Other deferred credits and liabilities | — | — | |||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | 6 | $ | 1 | $ | 4 | $ | 1 | ||||||||||||||||
Total | $ | 21 | $ | 27 | $ | 225 | $ | 56 | ||||||||||||||||
The Company's derivative contracts are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | ||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 13 | $ | 24 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 201 | $ | 56 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (9 | ) | (22 | ) | Gross amounts not offset in the Balance Sheet (b) | (9 | ) | (22 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 4 | $ | 2 | Net energy-related derivative liabilities | $ | 192 | $ | 34 | |||||||||||||||
Interest rate derivatives presented in the Balance Sheet (a) | $ | 8 | $ | 3 | Interest rate derivatives presented in the Balance Sheet (a) | $ | 24 | $ | — | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (8 | ) | — | Gross amounts not offset in the Balance Sheet (b) | (8 | ) | — | |||||||||||||||||
Net interest rate derivative assets | $ | — | $ | 3 | Net interest rate derivative liabilities | $ | 16 | $ | — | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | ||||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (118 | ) | $ | (26 | ) | Other regulatory liabilities, current | $ | 7 | $ | 16 | ||||||||||||
Other regulatory assets, deferred | (79 | ) | (29 | ) | Other regulatory liabilities, deferred | — | 7 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (197 | ) | $ | (55 | ) | $ | 7 | $ | 23 | ||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for Southern Company. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on Southern Company's statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on Southern Company's statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases. | ||||||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from OCI into earnings were immaterial for Southern Company. | ||||||||||||||||||||||||
There was no material ineffectiveness recorded in earnings for any period presented. | ||||||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related and foreign currency derivatives not designated as hedging instruments on the statements of income were immaterial for Southern Company. | ||||||||||||||||||||||||
For the Southern Company system's energy-related derivatives not designated as hedging instruments, a portion of the pre-tax realized and unrealized gains and losses was associated with hedging fuel price risk of certain PPA customers and had no impact on net income or on fuel expense as presented in the Company's statements of income for the years ended December 31, 2014, 2013, and 2012. This third party hedging activity has been discontinued. | ||||||||||||||||||||||||
Contingent Features | ||||||||||||||||||||||||
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At December 31, 2014, Southern Company's collateral posted with its derivative counterparties was immaterial. | ||||||||||||||||||||||||
At December 31, 2014, the fair value of derivative liabilities with contingent features was $54 million. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54 million and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. | ||||||||||||||||||||||||
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. | ||||||||||||||||||||||||
Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. | ||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
DERIVATIVES | DERIVATIVES | |||||||||||||||||||||||
The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. | ||||||||||||||||||||||||
Energy-Related Derivatives | ||||||||||||||||||||||||
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Alabama PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. | ||||||||||||||||||||||||
To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. | ||||||||||||||||||||||||
Energy-related derivative contracts are accounted for in one of three methods: | ||||||||||||||||||||||||
• | Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the energy cost recovery clause. | |||||||||||||||||||||||
• | Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. | |||||||||||||||||||||||
• | Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. | |||||||||||||||||||||||
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. | ||||||||||||||||||||||||
At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: | ||||||||||||||||||||||||
Net Purchased | Longest Hedge | Longest Non-Hedge | ||||||||||||||||||||||
mmBtu | Date | Date | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
56 | 2017 | — | ||||||||||||||||||||||
For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to revenue and fuel expense for the 12-month period ending December 31, 2015 are immaterial. | ||||||||||||||||||||||||
Interest Rate Derivatives | ||||||||||||||||||||||||
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. | ||||||||||||||||||||||||
At December 31, 2014, the following interest rate derivatives were outstanding: | ||||||||||||||||||||||||
Notional | Interest | Weighted Average Interest | Hedge | Fair Value | ||||||||||||||||||||
Amount | Rate | Rate Paid | Maturity | Gain (Loss) | ||||||||||||||||||||
Received | Date | December 31, | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Cash Flow Hedges of Forecasted Debt | ||||||||||||||||||||||||
$200 | 3-month | 2.93% | Oct-25 | $ | (8 | ) | ||||||||||||||||||
LIBOR | ||||||||||||||||||||||||
The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2015 are $3 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2035. | ||||||||||||||||||||||||
Derivative Financial Statement Presentation and Amounts | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 1 | $ | 5 | Other current liabilities | $ | 32 | $ | 3 | ||||||||||||||
Other deferred charges and assets | — | 2 | Other deferred credits and liabilities | 21 | 5 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 | $ | 7 | $ | 53 | $ | 8 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow hedges | ||||||||||||||||||||||||
Interest rate derivatives: | Other current assets | $ | — | $ | — | Other current liabilities | $ | 8 | $ | — | ||||||||||||||
Total | $ | 1 | $ | 7 | $ | 61 | $ | 8 | ||||||||||||||||
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2014 and 2013. | ||||||||||||||||||||||||
The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure table below. | ||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 1 | $ | 7 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 53 | $ | 8 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | — | (5 | ) | Gross amounts not offset in the Balance Sheet (b) | — | (5 | ) | |||||||||||||||||
Net energy-related derivative assets | $ | 1 | $ | 2 | Net energy-related derivative liabilities | $ | 53 | $ | 3 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
At December 31, 2014 and 2013, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: | ||||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (32 | ) | $ | (3 | ) | Other current liabilities | $ | 1 | $ | 5 | ||||||||||||
Other regulatory assets, deferred | (21 | ) | (5 | ) | Other regulatory liabilities, deferred | — | 2 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (53 | ) | $ | (8 | ) | $ | 1 | $ | 7 | ||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: | ||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in | Gain (Loss) Reclassified from Accumulated OCI into Income | ||||||||||||||||||||||
OCI on Derivative | (Effective Portion) | |||||||||||||||||||||||
(Effective Portion) | Amount | |||||||||||||||||||||||
Derivative Category | 2014 | 2013 | 2012 | Statements of Income | 2014 | 2013 | 2012 | |||||||||||||||||
Location | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Interest rate derivatives | $ | (8 | ) | $ | — | $ | (18 | ) | Interest expense, net of amounts capitalized | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | ||||||
There was no material ineffectiveness recorded in earnings for any period presented. | ||||||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was not material. | ||||||||||||||||||||||||
Contingent Features | ||||||||||||||||||||||||
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2014, the Company's collateral posted with its derivative counterparties was not material. | ||||||||||||||||||||||||
At December 31, 2014, the fair value of derivative liabilities with contingent features was $18 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. | ||||||||||||||||||||||||
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. | ||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
DERIVATIVES | DERIVATIVES | |||||||||||||||||||||||
The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 10 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. | ||||||||||||||||||||||||
Energy-Related Derivatives | ||||||||||||||||||||||||
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages a fuel-hedging program, implemented per the guidelines of the Georgia PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. | ||||||||||||||||||||||||
To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. | ||||||||||||||||||||||||
Energy-related derivative contracts are accounted for in one of two methods: | ||||||||||||||||||||||||
• | Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel-hedging program, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery mechanism. | |||||||||||||||||||||||
• | Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. | |||||||||||||||||||||||
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. | ||||||||||||||||||||||||
At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions totaled 46 million mmBtu, all of which expire by 2017, which is the longest hedge date. | ||||||||||||||||||||||||
In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The expected volume of natural gas subject to such a feature is 4 million mmBtu for the Company. | ||||||||||||||||||||||||
Interest Rate Derivatives | ||||||||||||||||||||||||
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains and losses and the hedged items' fair value gains and losses attributable to interest rate risk are both recorded directly to earnings, providing an offset, with any differences representing ineffectiveness. | ||||||||||||||||||||||||
At December 31, 2014, the following interest rate derivatives were outstanding: | ||||||||||||||||||||||||
Notional | Interest | Weighted Average Interest | Hedge | Fair Value | ||||||||||||||||||||
Amount | Rate | Rate Paid | Maturity | Gain (Loss) | ||||||||||||||||||||
Received | Date | December 31, | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Cash Flow Hedges of Forecasted Debt | ||||||||||||||||||||||||
$ | 350 | 3-month LIBOR | 2.57% | May-25 | $ | (6 | ) | |||||||||||||||||
350 | 3-month LIBOR | 2.57% | Nov-25 | (2 | ) | |||||||||||||||||||
Cash Flow Hedges of Existing Debt | ||||||||||||||||||||||||
250 | 3-month LIBOR + 0.32% | 0.75% | Mar-16 | — | ||||||||||||||||||||
200 | 3-month LIBOR + 0.40% | 1.01% | Aug-16 | — | ||||||||||||||||||||
Fair value hedges of existing debt | ||||||||||||||||||||||||
250 | 5.40% | 3-month LIBOR + 4.02% | Jun-18 | (1 | ) | |||||||||||||||||||
200 | 4.25% | 3-month LIBOR + 2.46% | Dec-19 | — | ||||||||||||||||||||
Total | $ | 1,600 | $ | (9 | ) | |||||||||||||||||||
The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2015 are immaterial. The Company has deferred gains and losses related to interest rate derivative settlements of cash flow hedges that are expected to be amortized into earnings through 2037. | ||||||||||||||||||||||||
Derivative Financial Statement Presentation and Amounts | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 6 | $ | 3 | Liabilities from risk management activities | $ | 23 | $ | 13 | ||||||||||||||
Other deferred charges and assets | 1 | 2 | Other deferred credits and liabilities | 4 | 8 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 7 | $ | 5 | $ | 27 | $ | 21 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||||||||||||
Interest rate derivatives: | Other current assets | $ | 5 | $ | — | Liabilities from risk management activities | $ | 9 | $ | — | ||||||||||||||
Other deferred charges and assets | 1 | — | Other deferred credits and liabilities | 5 | — | |||||||||||||||||||
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 6 | $ | — | $ | 14 | $ | — | ||||||||||||||||
Total | $ | 13 | $ | 5 | $ | 41 | $ | 21 | ||||||||||||||||
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2014 and 2013. | ||||||||||||||||||||||||
The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | ||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 7 | $ | 5 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 27 | $ | 21 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (7 | ) | (5 | ) | Gross amounts not offset in the Balance Sheet (b) | (7 | ) | (5 | ) | |||||||||||||||
Net energy-related derivative assets | $ | — | $ | — | Net energy-related derivative liabilities | $ | 20 | $ | 16 | |||||||||||||||
Interest rate derivatives presented in the Balance Sheet (a) | $ | 6 | $ | — | Interest rate derivatives presented in the Balance Sheet (a) | $ | 14 | $ | — | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (6 | ) | — | Gross amounts not offset in the Balance Sheet (b) | (6 | ) | — | |||||||||||||||||
Net interest rate derivative assets | $ | — | $ | — | Net interest rate derivative liabilities | $ | 8 | $ | — | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | ||||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (23 | ) | $ | (13 | ) | Other regulatory liabilities, current | $ | 6 | $ | 3 | ||||||||||||
Other regulatory assets, deferred | (4 | ) | (8 | ) | Other deferred credits and liabilities | 1 | 2 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (27 | ) | $ | (21 | ) | $ | 7 | $ | 5 | ||||||||||||||
For the year ended December 31, 2014, the pre-tax effect of interest rate derivatives designated as fair value hedging instruments on the statement of income was immaterial on a gross basis for the Company. Furthermore, the pre-tax effect of interest rate derivatives designated as fair value hedging instruments on the Company's statement of income was offset by changes to the carrying value of the long-term debt. The gains and losses related to interest rate derivative settlements of fair value hedges are recorded directly to earnings. | ||||||||||||||||||||||||
The pre-tax effects of interest rate derivatives designated as cash flow hedging instruments include $8 million of losses recognized in OCI for the year ended December 31, 2014 and amounts reclassified from accumulated OCI into earnings that were immaterial for all years presented. | ||||||||||||||||||||||||
There was no material ineffectiveness recorded in earnings for any period presented. The pre-tax effect of energy-related derivatives not designated as hedging instruments on the statements of income was immaterial for all years presented. | ||||||||||||||||||||||||
Contingent Features | ||||||||||||||||||||||||
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2014, the Company's collateral posted with its derivative counterparties was immaterial. | ||||||||||||||||||||||||
At December 31, 2014, the fair value of derivative liabilities with contingent features was $4 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. | ||||||||||||||||||||||||
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. | ||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
DERIVATIVES | DERIVATIVES | |||||||||||||||||||||||
The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and may enter into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. | ||||||||||||||||||||||||
Energy-Related Derivatives | ||||||||||||||||||||||||
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Florida PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. | ||||||||||||||||||||||||
To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. | ||||||||||||||||||||||||
Energy-related derivative contracts are accounted for in one of two methods: | ||||||||||||||||||||||||
• | Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the fuel cost recovery clause. | |||||||||||||||||||||||
• | Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. | |||||||||||||||||||||||
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. | ||||||||||||||||||||||||
At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions totaled 84.59 million mmBtu for the Company, with the longest hedge date of 2019 over which it is hedging its exposure to the variability in future cash flows for forecasted transactions. | ||||||||||||||||||||||||
Interest Rate Derivatives | ||||||||||||||||||||||||
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. | ||||||||||||||||||||||||
At December 31, 2014, there were no interest rate derivatives outstanding. | ||||||||||||||||||||||||
The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2015 are not material. The Company has deferred gains and losses that are expected to be amortized into earnings through 2020. | ||||||||||||||||||||||||
Derivative Financial Statement Presentation and Amounts | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the fair value of energy-related derivatives was reflected in the balance sheets as follows: | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 34 | $ | 4,893 | Liabilities from risk management activities | $ | 36,922 | $ | 6,470 | ||||||||||||||
Other deferred charges and assets | 78 | 2,069 | Other deferred credits and liabilities | 35,502 | 10,573 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 112 | $ | 6,962 | $ | 72,424 | $ | 17,043 | ||||||||||||||||
Energy-related derivatives not designated as hedging instruments were immaterial on the balance sheets for 2014 and 2013. | ||||||||||||||||||||||||
The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | ||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 125 | $ | 6,962 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 72,435 | $ | 17,043 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (123 | ) | (5,775 | ) | Gross amounts not offset in the Balance Sheet (b) | (123 | ) | (5,775 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 2 | $ | 1,187 | Net energy-related derivative liabilities | $ | 72,312 | $ | 11,268 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | ||||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (36,922 | ) | $ | (6,470 | ) | Other regulatory liabilities, current | $ | 34 | $ | 4,893 | ||||||||||||
Other regulatory assets, deferred | (35,502 | ) | (10,573 | ) | Other regulatory liabilities, deferred | 78 | 2,069 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (72,424 | ) | $ | (17,043 | ) | $ | 112 | $ | 6,962 | ||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows: | ||||||||||||||||||||||||
Derivatives in Cash | Gain (Loss) Recognized in | Gain (Loss) Reclassified from Accumulated | ||||||||||||||||||||||
Flow Hedging Relationships | OCI on Derivative | OCI into Income (Effective Portion) | ||||||||||||||||||||||
(Effective Portion) | Amount | |||||||||||||||||||||||
Derivative Category | 2014 | 2013 | 2012 | Statements of Income Location | 2014 | 2013 | 2012 | |||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Interest rate derivatives | $— | $— | $— | Interest expense, net of amounts capitalized | ($606) | ($769) | ($933) | |||||||||||||||||
There was no material ineffectiveness recorded in earnings for any period presented. | ||||||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were not material. | ||||||||||||||||||||||||
Contingent Features | ||||||||||||||||||||||||
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2014, the Company's collateral posted with its derivative counterparties was not material. | ||||||||||||||||||||||||
At December 31, 2014, the fair value of derivative liabilities with contingent features was $20.5 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54.5 million and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. | ||||||||||||||||||||||||
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. | ||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
DERIVATIVES | DERIVATIVES | |||||||||||||||||||||||
The Company is exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 9 for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities. | ||||||||||||||||||||||||
Energy-Related Derivatives | ||||||||||||||||||||||||
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in commodity fuel prices and prices of electricity. The Company manages fuel-hedging programs, implemented per the guidelines of the Mississippi PSC, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. | ||||||||||||||||||||||||
To mitigate residual risks relative to movements in electricity prices, the Company may enter into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. | ||||||||||||||||||||||||
Energy-related derivative contracts are accounted for in one of three methods: | ||||||||||||||||||||||||
• | Regulatory Hedges – Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company's fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses. | |||||||||||||||||||||||
• | Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of operations in the same period as the hedged transactions are reflected in earnings. | |||||||||||||||||||||||
• | Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of operations as incurred. | |||||||||||||||||||||||
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. | ||||||||||||||||||||||||
At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: | ||||||||||||||||||||||||
Net Purchased | Longest Hedge | Longest Non-Hedge | ||||||||||||||||||||||
mmBtu | Date | Date | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
54 | 2018 | — | ||||||||||||||||||||||
For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2015 are immaterial. | ||||||||||||||||||||||||
Interest Rate Derivatives | ||||||||||||||||||||||||
The Company may also enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to income. | ||||||||||||||||||||||||
At December 31, 2014, there were no interest rate derivatives outstanding. | ||||||||||||||||||||||||
The estimated pre-tax losses that will be reclassified from accumulated OCI to interest expense for the 12-month period ending December 31, 2015 are $1.4 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2022. | ||||||||||||||||||||||||
Foreign Currency Derivatives | ||||||||||||||||||||||||
The Company may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as a fair value hedge where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as a cash flow hedge where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. Any ineffectiveness is typically recorded directly to earnings; however, the Company has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset. During 2011, certain fair value hedges were de-designated and subsequently settled in 2012. The ineffectiveness related to the de-designated hedges was recorded as a regulatory asset and was immaterial to the Company. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. | ||||||||||||||||||||||||
At December 31, 2014, there were no foreign currency derivatives outstanding. | ||||||||||||||||||||||||
Derivative Financial Statement Presentation and Amounts | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the fair value of energy-related derivatives and foreign currency derivatives was reflected in the balance sheets as follows: | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | ||||||||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 30 | $ | 3,352 | Other current liabilities | $ | 26,259 | $ | 3,652 | ||||||||||||||
Other deferred charges and assets | 22 | 1,451 | Other deferred credits and liabilities | 19,159 | 6,629 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 52 | $ | 4,803 | $ | 45,418 | $ | 10,281 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||||||||||||
Foreign currency derivatives: | Other current assets | $ | — | $ | — | Other current liabilities | $ | — | $ | 1 | ||||||||||||||
Total | $ | 52 | $ | 4,803 | $ | 45,418 | $ | 10,282 | ||||||||||||||||
Energy-related derivatives not designated as hedging instruments were immaterial for 2014 and 2013. The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | ||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 65 | $ | 4,803 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 45,429 | $ | 10,282 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (64 | ) | (3,856 | ) | Gross amounts not offset in the Balance Sheet (b) | (64 | ) | (3,856 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 1 | $ | 947 | Net energy-related derivative liabilities | $ | 45,365 | $ | 6,426 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | ||||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (26,259 | ) | $ | (3,652 | ) | Other regulatory liabilities, current | $ | 30 | $ | 3,352 | ||||||||||||
Other regulatory assets, deferred | (19,159 | ) | (6,629 | ) | Other regulatory liabilities, deferred | 22 | 1,451 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (45,418 | ) | $ | (10,281 | ) | $ | 52 | $ | 4,803 | ||||||||||||||
The pre-tax effects of unrealized gains (losses) arising from energy-related derivative instruments not designated as hedging instruments was immaterial for 2014 and 2013. | ||||||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were as follows: | ||||||||||||||||||||||||
Derivatives in Cash Flow | Gain (Loss) Recognized in | Gain (Loss) Reclassified from Accumulated | ||||||||||||||||||||||
Hedging Relationships | OCI on Derivative | OCI into Income | ||||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||||
Amount | ||||||||||||||||||||||||
Derivative Category | 2014 | 2013 | 2012 | Statements of Operations Location | 2014 | 2013 | 2012 | |||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives | $ | — | $ | — | $ | — | Fuel | $ | — | $ | — | $ | — | |||||||||||
Interest rate derivatives | — | — | (774 | ) | Interest Expense | (1,375 | ) | (1,375 | ) | (1,073 | ) | |||||||||||||
Total | $ | — | $ | — | $ | (774 | ) | $ | (1,375 | ) | $ | (1,375 | ) | $ | (1,073 | ) | ||||||||
There was no material ineffectiveness recorded in earnings for any period presented. | ||||||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of operations were immaterial. | ||||||||||||||||||||||||
For the years ended December 31, 2014 and 2013, the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on the Company's statements of operations were immaterial. For the year ended December 31, 2012, the pre-tax effect of foreign currency derivatives designated as fair value hedging instruments, which include a pretax loss associated with the de-designated hedges prior to de-designation, was a $0.6 million gain. These amounts were offset by changes in the fair value of the purchase commitment related to equipment purchases. Therefore, there is no impact on the Company's statements of operations. | ||||||||||||||||||||||||
Contingent Features | ||||||||||||||||||||||||
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2014, the Company's collateral posted with its derivative counterparties was immaterial. | ||||||||||||||||||||||||
At December 31, 2014, the fair value of derivative liabilities with contingent features was $9.9 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54.5 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. | ||||||||||||||||||||||||
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. | ||||||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
DERIVATIVES | DERIVATIVES | |||||||||||||||||||||||
The Company is exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company's policies in areas such as counterparty exposure and risk management practices. The Company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note 8 herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. | ||||||||||||||||||||||||
Energy-Related Derivatives | ||||||||||||||||||||||||
The Company enters into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. The Company has limited exposure to market volatility in commodity fuel prices and prices of electricity because its long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the Company has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. | ||||||||||||||||||||||||
To mitigate residual risks relative to movements in electricity prices, the Company enters into physical fixed-price or heat rate contracts for the purchase and sale of electricity through the wholesale electricity market. To mitigate residual risks relative to movements in gas prices, the Company may enter into fixed-price contracts for natural gas purchases; however, a significant portion of contracts are priced at market. | ||||||||||||||||||||||||
Energy-related derivative contracts are accounted for in one of two methods: | ||||||||||||||||||||||||
• | Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges which are used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings. | |||||||||||||||||||||||
• | Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred. | |||||||||||||||||||||||
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered. | ||||||||||||||||||||||||
At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions totaled 3.4 million mmBtu, all of which expire by 2017, which is the longest non-hedge date. At December 31, 2014, the net volume of energy-related derivative contracts for power positions was immaterial. In addition to the volume discussed above, the Company enters into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 1.0 million mmBtu. | ||||||||||||||||||||||||
For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending December 31, 2015 are immaterial. | ||||||||||||||||||||||||
Interest Rate Derivatives | ||||||||||||||||||||||||
The Company may also enter into interest rate derivatives from time to time to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges, where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness, which is recorded directly to earnings. | ||||||||||||||||||||||||
At December 31, 2014, there were no interest rate derivatives outstanding. | ||||||||||||||||||||||||
The estimated pre-tax loss that will be reclassified from AOCI to interest expense for the 12-month period ending December 31, 2015 is $1.0 million. The Company has deferred gains and losses that are expected to be amortized into earnings through 2016. | ||||||||||||||||||||||||
Derivative Financial Statement Presentation and Amounts | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the fair value of energy-related derivatives was reflected in the balance sheets as follows: | ||||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Energy-related derivatives: | Assets from risk management activities | $ | 5.3 | $ | 0.2 | Other current liabilities | $ | 3.5 | $ | 0.6 | ||||||||||||||
Other deferred charges and assets – non-affiliated | 0.2 | 0.4 | Other deferred credits and liabilities – non-affiliated | 0.1 | — | |||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | 5.5 | $ | 0.6 | $ | 3.6 | $ | 0.6 | ||||||||||||||||
The derivative contracts of the Company are not subject to master netting arrangements or similar agreements and are reported gross on the Company's financial statements. Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below. | ||||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 5.5 | $ | 0.6 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 3.6 | $ | 0.6 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (0.1 | ) | (0.1 | ) | Gross amounts not offset in the Balance Sheet (b) | (0.1 | ) | (0.1 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 5.4 | $ | 0.5 | Net energy-related derivative liabilities | $ | 3.5 | $ | 0.5 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows: | ||||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Reclassified from AOCI into Income | |||||||||||||||||||||||
(Effective Portion) | ||||||||||||||||||||||||
Amount | ||||||||||||||||||||||||
Derivative Category | Statements of Income Location | 2014 | 2013 | 2012 | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Energy-related derivatives | Depreciation and amortization | $ | 0.4 | $ | 0.4 | $ | 0.4 | |||||||||||||||||
Interest rate derivatives | Interest expense, net of amounts capitalized | (0.9 | ) | (6.5 | ) | (10.5 | ) | |||||||||||||||||
Total | $ | (0.5 | ) | $ | (6.1 | ) | $ | (10.1 | ) | |||||||||||||||
There was no material ineffectiveness recorded in earnings for any period presented. | ||||||||||||||||||||||||
For the Company's energy-related derivatives not designated as hedging instruments, a portion of the pre-tax realized and unrealized gains and losses is associated with hedging fuel price risk of certain PPA customers and has no impact on net income or on fuel expense as presented in the Company's statements of income. The pre-tax effects of energy-related derivatives not designated as hedging instruments on the Company's statements of income were immaterial for the years ended December 31, 2014, 2013, and 2012. This third party hedging activity has been discontinued. | ||||||||||||||||||||||||
Contingent Features | ||||||||||||||||||||||||
The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain affiliated companies. At December 31, 2014, the amount of collateral posted with its derivative counterparties was immaterial. | ||||||||||||||||||||||||
At December 31, 2014, the fair value of derivative liabilities with contingent features was $1.5 million. However, because of joint and several liability features underlying these derivatives, the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $54.5 million, and include certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. | ||||||||||||||||||||||||
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance. |
Segment_and_Related_Informatio
Segment and Related Information | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||||||||||||||
SEGMENT AND RELATED INFORMATION | SEGMENT AND RELATED INFORMATION | |||||||||||||||||||||||||||
The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. | ||||||||||||||||||||||||||||
Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $383 million, $346 million, and $425 million in 2014, 2013, and 2012, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the years ended December 31, 2014, 2013, and 2012 was as follows: | ||||||||||||||||||||||||||||
Electric Utilities | ||||||||||||||||||||||||||||
Traditional | Southern | Eliminations | Total | All | Eliminations | Consolidated | ||||||||||||||||||||||
Operating | Power | Other | ||||||||||||||||||||||||||
Companies | ||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||
Operating revenues | $ | 17,354 | $ | 1,501 | $ | (449 | ) | $ | 18,406 | $ | 159 | $ | (98 | ) | $ | 18,467 | ||||||||||||
Depreciation and amortization | 1,709 | 220 | — | 1,929 | 16 | — | 1,945 | |||||||||||||||||||||
Interest income | 17 | 1 | — | 18 | 3 | (2 | ) | 19 | ||||||||||||||||||||
Interest expense | 705 | 89 | — | 794 | 43 | (2 | ) | 835 | ||||||||||||||||||||
Income taxes | 1,056 | (3 | ) | — | 1,053 | (76 | ) | — | 977 | |||||||||||||||||||
Segment net income (loss)(a) (b) | 1,797 | 172 | — | 1,969 | (3 | ) | (3 | ) | 1,963 | |||||||||||||||||||
Total assets | 64,644 | 5,550 | (131 | ) | 70,063 | 1,156 | (296 | ) | 70,923 | |||||||||||||||||||
Gross property additions | 5,568 | 942 | — | 6,510 | 11 | 1 | 6,522 | |||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||
Operating revenues | $ | 16,136 | $ | 1,275 | $ | (376 | ) | $ | 17,035 | $ | 139 | $ | (87 | ) | $ | 17,087 | ||||||||||||
Depreciation and amortization | 1,711 | 175 | — | 1,886 | 15 | — | 1,901 | |||||||||||||||||||||
Interest income | 17 | 1 | — | 18 | 2 | (1 | ) | 19 | ||||||||||||||||||||
Interest expense | 714 | 74 | — | 788 | 36 | — | 824 | |||||||||||||||||||||
Income taxes | 889 | 46 | — | 935 | (85 | ) | (1 | ) | 849 | |||||||||||||||||||
Segment net income (loss)(a) (b) | 1,486 | 166 | — | 1,652 | (10 | ) | 2 | 1,644 | ||||||||||||||||||||
Total assets | 59,447 | 4,429 | (101 | ) | 63,775 | 1,077 | (306 | ) | 64,546 | |||||||||||||||||||
Gross property additions | 5,226 | 633 | — | 5,859 | 9 | — | 5,868 | |||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||
Operating revenues | $ | 15,730 | $ | 1,186 | $ | (438 | ) | $ | 16,478 | $ | 141 | $ | (82 | ) | $ | 16,537 | ||||||||||||
Depreciation and amortization | 1,629 | 143 | — | 1,772 | 15 | — | 1,787 | |||||||||||||||||||||
Interest income | 21 | 1 | — | 22 | 19 | (1 | ) | 40 | ||||||||||||||||||||
Interest expense | 757 | 63 | — | 820 | 39 | — | 859 | |||||||||||||||||||||
Income taxes | 1,307 | 93 | — | 1,400 | (66 | ) | — | 1,334 | ||||||||||||||||||||
Segment net income (loss)(a) | 2,145 | 175 | 1 | 2,321 | 33 | (4 | ) | 2,350 | ||||||||||||||||||||
Total assets | 58,600 | 3,780 | (129 | ) | 62,251 | 1,116 | (218 | ) | 63,149 | |||||||||||||||||||
Gross property additions | 4,813 | 241 | — | 5,054 | 5 | — | 5,059 | |||||||||||||||||||||
(a) | After dividends on preferred and preference stock of subsidiaries. | |||||||||||||||||||||||||||
(b) | Segment net income (loss) for the traditional operating companies in 2014 and 2013 includes $868 million in pre-tax charges ($536 million after tax) and $1.2 billion in pre-tax charges ($729 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. | |||||||||||||||||||||||||||
Products and Services | ||||||||||||||||||||||||||||
Electric Utilities' Revenues | ||||||||||||||||||||||||||||
Year | Retail | Wholesale | Other | Total | ||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
2014 | $15,550 | $2,184 | $672 | $18,406 | ||||||||||||||||||||||||
2013 | 14,541 | 1,855 | 639 | 17,035 | ||||||||||||||||||||||||
2012 | 14,187 | 1,675 | 616 | 16,478 |
Noncontrolling_Interest
Noncontrolling Interest (Southern Power [Member]) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Southern Power [Member] | ||||||||||||
Noncontrolling Interest [Line Items] | ||||||||||||
NONCONTROLLING INTEREST | NONCONTROLLING INTEREST | |||||||||||
The following table details the components of redeemable noncontrolling interests for the years ended December 31: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Beginning balance | $ | 28.8 | $ | 8.1 | $ | 3.8 | ||||||
Net income attributable to redeemable noncontrolling interest | 4 | 3.9 | 0.9 | |||||||||
Distributions to redeemable noncontrolling interest | (1.1 | ) | (0.5 | ) | — | |||||||
Capital contributions from redeemable noncontrolling interest | 7.5 | 17.3 | 3.4 | |||||||||
Ending balance | $ | 39.2 | $ | 28.8 | $ | 8.1 | ||||||
For the year ended December 31, 2014, net income included in the consolidated statements of changes in stockholders' equity is reconciled to net income presented in the consolidated statements of income as follows: | ||||||||||||
2014 | ||||||||||||
Net income attributable to Southern Power Company | $ | 172.3 | ||||||||||
Net loss attributable to noncontrolling interest | (1.2 | ) | ||||||||||
Net income attributable to redeemable noncontrolling interest | 4 | |||||||||||
Net income | $ | 175.1 | ||||||||||
For the years ended December 31, 2013 and 2012, net income attributable to redeemable noncontrolling interest was $3.9 million and $0.9 million, respectively, and was included in "Other income (expense), net" in the consolidated statements of income. |
Quarterly_Financial_Informatio
Quarterly Financial Information (Unaudited) | 12 Months Ended | |||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||||||||||||||||
Summarized quarterly financial information for 2014 and 2013 is as follows: | ||||||||||||||||||||||||||||||||
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries | Per Common Share | |||||||||||||||||||||||||||||||
Operating | Operating | Basic | Diluted Earnings | Trading | ||||||||||||||||||||||||||||
Revenues | Income | Earnings | Price Range | |||||||||||||||||||||||||||||
Quarter Ended | Dividends | High | Low | |||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 4,644 | $ | 700 | $ | 351 | $ | 0.39 | $ | 0.39 | $ | 0.5075 | $ | 44 | $ | 40.27 | ||||||||||||||||
Jun-14 | 4,467 | 1,103 | 611 | 0.68 | 0.68 | 0.525 | 46.81 | 42.55 | ||||||||||||||||||||||||
Sep-14 | 5,339 | 1,278 | 718 | 0.8 | 0.8 | 0.525 | 45.47 | 41.87 | ||||||||||||||||||||||||
Dec-14 | 4,017 | 561 | 283 | 0.31 | 0.31 | 0.525 | 51.28 | 43.55 | ||||||||||||||||||||||||
Mar-13 | $ | 3,897 | $ | 325 | $ | 81 | $ | 0.09 | $ | 0.09 | $ | 0.49 | $ | 46.95 | $ | 42.82 | ||||||||||||||||
Jun-13 | 4,246 | 640 | 297 | 0.34 | 0.34 | 0.5075 | 48.74 | 42.32 | ||||||||||||||||||||||||
Sep-13 | 5,017 | 1,491 | 852 | 0.97 | 0.97 | 0.5075 | 45.75 | 40.63 | ||||||||||||||||||||||||
Dec-13 | 3,927 | 799 | 414 | 0.47 | 0.47 | 0.5075 | 42.94 | 40.03 | ||||||||||||||||||||||||
As a result of the revisions to the cost estimate for the Kemper IGCC, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $70.0 million ($43.2 million after tax) in the fourth quarter 2014, $418.0 million ($258.1 million after tax) in the third quarter 2014, $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, and $540.0 million ($333.5 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.05 billion ($1.26 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through December 31, 2014. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||||||||||
The Southern Company system's business is influenced by seasonal weather conditions. | ||||||||||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||||||||||||||||
Summarized quarterly financial information for 2014 and 2013 is as follows: | ||||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income After Dividends on Preferred and Preference Stock | |||||||||||||||||||||||||||||
Revenues | Income | |||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 1,508 | $ | 381 | $ | 187 | ||||||||||||||||||||||||||
Jun-14 | 1,437 | 357 | 173 | |||||||||||||||||||||||||||||
Sep-14 | 1,669 | 520 | 282 | |||||||||||||||||||||||||||||
Dec-14 | 1,328 | 267 | 119 | |||||||||||||||||||||||||||||
Mar-13 | $ | 1,308 | $ | 307 | $ | 141 | ||||||||||||||||||||||||||
Jun-13 | 1,392 | 357 | 173 | |||||||||||||||||||||||||||||
Sep-13 | 1,604 | 500 | 258 | |||||||||||||||||||||||||||||
Dec-13 | 1,314 | 312 | 140 | |||||||||||||||||||||||||||||
The Company's business is influenced by seasonal weather conditions. | ||||||||||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||||||||||||||||
Summarized quarterly financial information for 2014 and 2013 is as follows: | ||||||||||||||||||||||||||||||||
Quarter Ended | Operating Revenues | Operating Income | Net Income After Dividends on Preferred and Preference Stock | |||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 2,269 | $ | 516 | $ | 266 | ||||||||||||||||||||||||||
Jun-14 | 2,186 | 572 | 311 | |||||||||||||||||||||||||||||
Sep-14 | 2,631 | 920 | 525 | |||||||||||||||||||||||||||||
Dec-14 | 1,902 | 288 | 123 | |||||||||||||||||||||||||||||
Mar-13 | $ | 1,882 | $ | 412 | $ | 197 | ||||||||||||||||||||||||||
Jun-13 | 2,042 | 552 | 282 | |||||||||||||||||||||||||||||
Sep-13 | 2,484 | 872 | 487 | |||||||||||||||||||||||||||||
Dec-13 | 1,866 | 404 | 208 | |||||||||||||||||||||||||||||
The Company's business is influenced by seasonal weather conditions. | ||||||||||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||||||||||||||||
Summarized quarterly financial information for 2014 and 2013 is as follows: | ||||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income After Dividends on Preference Stock | |||||||||||||||||||||||||||||
Revenues | Income | |||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 407,132 | $ | 73,888 | $ | 36,743 | ||||||||||||||||||||||||||
Jun-14 | 383,531 | 68,877 | 34,097 | |||||||||||||||||||||||||||||
Sep-14 | 438,334 | 88,600 | 46,547 | |||||||||||||||||||||||||||||
Dec-14 | 361,485 | 49,850 | 22,789 | |||||||||||||||||||||||||||||
Mar-13 | $ | 326,274 | $ | 51,640 | $ | 21,792 | ||||||||||||||||||||||||||
Jun-13 | 371,173 | 69,151 | 32,582 | |||||||||||||||||||||||||||||
Sep-13 | 399,361 | 87,776 | 44,754 | |||||||||||||||||||||||||||||
Dec-13 | 343,493 | 56,436 | 25,301 | |||||||||||||||||||||||||||||
The Company's business is influenced by seasonal weather conditions. | ||||||||||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||||||||||||||||
Summarized quarterly financial information for 2014 and 2013 is as follows: | ||||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income (Loss) After Dividends on Preferred Stock | |||||||||||||||||||||||||||||
Revenues | Income (Loss) | |||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 331,161 | $ | (325,460 | ) | $ | (172,048 | ) | ||||||||||||||||||||||||
Jun-14 | 310,975 | 56,021 | 62,495 | |||||||||||||||||||||||||||||
Sep-14 | 354,623 | (349,010 | ) | (195,070 | ) | |||||||||||||||||||||||||||
Dec-14 | 245,852 | (70,721 | ) | (24,058 | ) | |||||||||||||||||||||||||||
Mar-13 | $ | 245,934 | $ | (429,148 | ) | $ | (246,321 | ) | ||||||||||||||||||||||||
Jun-13 | 306,435 | (388,395 | ) | (219,110 | ) | |||||||||||||||||||||||||||
Sep-13 | 325,206 | (79,890 | ) | (24,115 | ) | |||||||||||||||||||||||||||
Dec-13 | 267,582 | (24,412 | ) | 12,921 | ||||||||||||||||||||||||||||
As a result of the revisions to the cost estimate for the Kemper IGCC, the Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $70.0 million ($43.2 million after tax) in the fourth quarter 2014, $418.0 million ($258.1 million after tax) in the third quarter 2014, $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, $462.0 million ($285.3 million after tax) in the first quarter 2013, and $78.0 million ($48.2 million after tax) in the fourth quarter 2012. In the aggregate, the Company has incurred charges of $2.05 billion ($1.26 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through December 31, 2014. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||||||||||
The Company's business is influenced by seasonal weather conditions. | ||||||||||||||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | |||||||||||||||||||||||||||||||
Summarized quarterly financial information for 2014 and 2013 is as follows: | ||||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income | |||||||||||||||||||||||||||||
Revenues | Income | Attributable to | ||||||||||||||||||||||||||||||
Southern Power Company | ||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 350,854 | $ | 59,358 | $ | 33,471 | ||||||||||||||||||||||||||
Jun-14 | 328,803 | 51,073 | 30,812 | |||||||||||||||||||||||||||||
Sep-14 | 435,256 | 104,710 | 63,631 | |||||||||||||||||||||||||||||
Dec-14 | 386,336 | 40,138 | 44,386 | |||||||||||||||||||||||||||||
Mar-13 | $ | 302,947 | $ | 64,673 | $ | 29,192 | ||||||||||||||||||||||||||
Jun-13 | 307,255 | 55,024 | 27,922 | |||||||||||||||||||||||||||||
Sep-13 | 364,767 | 116,497 | 85,153 | |||||||||||||||||||||||||||||
Dec-13 | 300,257 | 53,781 | 23,266 | |||||||||||||||||||||||||||||
The Company's business is influenced by seasonal weather conditions. |
Valuation_and_Qualifying_Accou
Valuation and Qualifying Accounts | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS | THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES | |||||||||||||||||||
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012 | ||||||||||||||||||||
(Stated in Thousands of Dollars) | ||||||||||||||||||||
Additions | ||||||||||||||||||||
Description | Balance at Beginning of Period | Charged to Income | Charged to Other Accounts | Deductions (Note) | Balance at End of Period | |||||||||||||||
Provision for uncollectible accounts | ||||||||||||||||||||
2014 | $ | 17,855 | $ | 43,537 | $ | — | $ | 43,139 | $ | 18,253 | ||||||||||
2013 | 16,984 | 36,788 | — | 35,917 | 17,855 | |||||||||||||||
2012 | 26,155 | 35,305 | — | 44,476 | 16,984 | |||||||||||||||
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. | ||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS | ALABAMA POWER COMPANY | |||||||||||||||||||
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012 | ||||||||||||||||||||
(Stated in Thousands of Dollars) | ||||||||||||||||||||
Additions | ||||||||||||||||||||
Description | Balance at Beginning | Charged to | Charged to Other Accounts | Deductions | Balance at | |||||||||||||||
of Period | Income | (Note) | End of Period | |||||||||||||||||
Provision for uncollectible accounts | ||||||||||||||||||||
2014 | $ | 8,350 | $ | 14,309 | $ | — | $ | 13,516 | $ | 9,143 | ||||||||||
2013 | 8,450 | 12,327 | — | 12,427 | 8,350 | |||||||||||||||
2012 | 9,856 | 10,537 | — | 11,943 | 8,450 | |||||||||||||||
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. | ||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS | GEORGIA POWER COMPANY | |||||||||||||||||||
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012 | ||||||||||||||||||||
(Stated in Thousands of Dollars) | ||||||||||||||||||||
Additions | ||||||||||||||||||||
Description | Balance at Beginning | Charged to | Charged to Other | Deductions | Balance at End of Period | |||||||||||||||
of Period | Income | Accounts | (Note) | |||||||||||||||||
Provision for uncollectible accounts | ||||||||||||||||||||
2014 | $ | 5,074 | $ | 24,141 | $ | — | $ | 23,139 | $ | 6,076 | ||||||||||
2013 | 6,259 | 18,362 | — | 19,547 | 5,074 | |||||||||||||||
2012 | 13,038 | 20,995 | — | 27,774 | 6,259 | |||||||||||||||
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. | ||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS | GULF POWER COMPANY | |||||||||||||||||||
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012 | ||||||||||||||||||||
(Stated in Thousands of Dollars) | ||||||||||||||||||||
Additions | ||||||||||||||||||||
Description | Balance at Beginning | Charged to | Charged to Other | Deductions | Balance at End of Period | |||||||||||||||
of Period | Income | Accounts | (Note) | |||||||||||||||||
Provision for uncollectible accounts | ||||||||||||||||||||
2014 | $ | 1,131 | $ | 4,304 | $ | — | $ | 3,348 | $ | 2,087 | ||||||||||
2013 | 1,490 | 1,900 | — | 2,259 | 1,131 | |||||||||||||||
2012 | 1,962 | 2,611 | — | 3,083 | 1,490 | |||||||||||||||
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. | ||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||||||||||||||||
VALUATION AND QUALIFYING ACCOUNTS | MISSISSIPPI POWER COMPANY | |||||||||||||||||||
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS | ||||||||||||||||||||
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012 | ||||||||||||||||||||
(Stated in Thousands of Dollars) | ||||||||||||||||||||
Additions | ||||||||||||||||||||
Description | Balance at Beginning | Charged to | Charged to Other | Deductions | Balance at End of Period | |||||||||||||||
of Period | Income | Accounts | (Note) | |||||||||||||||||
Provision for uncollectible accounts | ||||||||||||||||||||
2014 | $ | 3,018 | $ | 562 | $ | — | $ | 2,755 | $ | 825 | ||||||||||
2013 | 373 | 3,757 | — | 1,112 | 3,018 | |||||||||||||||
2012 | 547 | 628 | — | 802 | 373 | |||||||||||||||
(Note) Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
General | General | |||||||||||||||||||||||
The Southern Company (Southern Company or the Company) is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
The financial statements reflect Southern Company's investments in the subsidiaries on a consolidated basis. The equity method is used for entities in which the Company has significant influence but does not control and for variable interest entities where the Company has an equity investment, but is not the primary beneficiary. All material intercompany transactions have been eliminated in consolidation. | ||||||||||||||||||||||||
The traditional operating companies, Southern Power, and certain of their subsidiaries are subject to regulation by the FERC, and the traditional operating companies are also subject to regulation by their respective state PSCs. The companies follow GAAP in the U.S. and comply with the accounting policies and practices prescribed by their respective commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | |||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities | |||||||||||||||||||||||
The traditional operating companies are subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Retiree benefit plans | $ | 3,469 | $ | 1,760 | (a,p) | |||||||||||||||||||
Deferred income tax charges | 1,458 | 1,376 | (b) | |||||||||||||||||||||
Loss on reacquired debt | 267 | 293 | (c) | |||||||||||||||||||||
Fuel-hedging-asset | 202 | 58 | (d,p) | |||||||||||||||||||||
Deferred PPA charges | 185 | 180 | (e,p) | |||||||||||||||||||||
Vacation pay | 177 | 171 | (f,p) | |||||||||||||||||||||
Under recovered regulatory clause revenues | 157 | 70 | (g) | |||||||||||||||||||||
Kemper IGCC regulatory assets | 148 | 76 | (h) | |||||||||||||||||||||
Asset retirement obligations-asset | 119 | 145 | (b,p) | |||||||||||||||||||||
Nuclear outage | 99 | 78 | (g) | |||||||||||||||||||||
Property damage reserves-asset | 98 | 37 | (i) | |||||||||||||||||||||
Cancelled construction projects | 67 | 70 | (j) | |||||||||||||||||||||
Environmental remediation-asset | 64 | 62 | (k,p) | |||||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 57 | 65 | (l) | |||||||||||||||||||||
Other regulatory assets | 195 | 222 | (m) | |||||||||||||||||||||
Other cost of removal obligations | (1,229 | ) | (1,289 | ) | (b) | |||||||||||||||||||
Kemper regulatory liability (Mirror CWIP) | (271 | ) | (91 | ) | (h) | |||||||||||||||||||
Deferred income tax credits | (192 | ) | (203 | ) | (b) | |||||||||||||||||||
Property damage reserves-liability | (181 | ) | (191 | ) | (n) | |||||||||||||||||||
Asset retirement obligations-liability | (130 | ) | (139 | ) | (b,p) | |||||||||||||||||||
Other regulatory liabilities | (95 | ) | (126 | ) | (o) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 4,664 | $ | 2,624 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the two-year period from January 2015 through December 2016 in accordance with Georgia Power's 2013 ARP. See Note 3 under "Retail Regulatory Matters – Georgia Power – Rate Plans" for additional information. At December 31, 2014, other cost of removal obligations included $8.4 million recorded as authorized by the Florida PSC in the Settlement Agreement approved in December 2013 (Gulf Power Settlement Agreement). | |||||||||||||||||||||||
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. | |||||||||||||||||||||||
(d) | Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||||||||||||||||||
(e) | Recovered over the life of the PPA for periods up to nine years. | |||||||||||||||||||||||
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(g) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years. | |||||||||||||||||||||||
(h) | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||||||||||||||
(i) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding eight years. | |||||||||||||||||||||||
(j) | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||||||||||||||||||
(k) | Recovered through the environmental cost recovery clause when the remediation is performed. | |||||||||||||||||||||||
(l) | Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years. | |||||||||||||||||||||||
(m) | Comprised of numerous immaterial components including property taxes, generation site selection/evaluation costs, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding 10 years or, as applicable, over the remaining life of the asset but not beyond 2031. | |||||||||||||||||||||||
(n) | Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. | |||||||||||||||||||||||
(o) | Comprised of numerous immaterial components including over-recovered regulatory clause revenues, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, nuclear disposal fees, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years. | |||||||||||||||||||||||
(p) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
In the event that a portion of a traditional operating company's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional operating company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power," and "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Revenues | Revenues | |||||||||||||||||||||||
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the traditional operating companies include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. | ||||||||||||||||||||||||
Southern Company's electric utility subsidiaries have a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | Fuel Costs | |||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. | ||||||||||||||||||||||||
Income and Other Taxes | Income and Other Taxes | |||||||||||||||||||||||
Southern Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
In accordance with regulatory requirements, deferred federal ITCs for the traditional operating companies are amortized over the average lives of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $22 million in 2014, $16 million in 2013, and $23 million in 2012. At December 31, 2014, all ITCs available to reduce federal income taxes payable had not been utilized. The remaining ITCs will be carried forward and utilized in future years. Additionally, several subsidiaries have state ITCs, which are recognized in the period in which the credit is claimed on the state income tax return. A portion of the state ITCs available to reduce state income taxes payable was not utilized currently and will be carried forward and utilized in future years. | ||||||||||||||||||||||||
Under the American Recovery and Reinvestment Act of 2009 and the American Taxpayer Relief Act of 2012 (ATRA), certain projects at Southern Power are eligible for federal ITCs or cash grants. Southern Power has elected to receive ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $11.4 million in 2014, $5.5 million in 2013, and $2.6 million in 2012. Also, Southern Power received cash related to federal ITCs under the renewable energy incentives of $74 million, $158 million, and $45 million for the years ended December 31, 2014, 2013, and 2012, respectively, which had a material impact on cash flows. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. The tax benefit of the related basis differences reduced income tax expense by $48 million in 2014, $31 million in 2013, and $8 million in 2012. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, Southern Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | Property, Plant, and Equipment | |||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. | ||||||||||||||||||||||||
The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 37,892 | $ | 35,360 | ||||||||||||||||||||
Transmission | 9,884 | 9,289 | ||||||||||||||||||||||
Distribution | 17,123 | 16,499 | ||||||||||||||||||||||
General | 4,198 | 3,958 | ||||||||||||||||||||||
Plant acquisition adjustment | 123 | 123 | ||||||||||||||||||||||
Utility plant in service | 69,220 | 65,229 | ||||||||||||||||||||||
Information technology equipment and software | 244 | 242 | ||||||||||||||||||||||
Communications equipment | 439 | 437 | ||||||||||||||||||||||
Other | 110 | 113 | ||||||||||||||||||||||
Other plant in service | 793 | 792 | ||||||||||||||||||||||
Total plant in service | $ | 70,013 | $ | 66,021 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific state PSC orders. Alabama Power and Georgia Power defer and amortize nuclear refueling costs over the unit's operating cycle. The refueling cycles for Alabama Power's Plant Farley and Georgia Power's Plants Hatch and Vogtle Units 1 and 2 range from 18 to 24 months, depending on the unit. | ||||||||||||||||||||||||
Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below: | ||||||||||||||||||||||||
Asset Balances at | ||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Office building | $ | 61 | $ | 61 | ||||||||||||||||||||
Nitrogen plant | 83 | 83 | ||||||||||||||||||||||
Computer-related equipment | 60 | 62 | ||||||||||||||||||||||
Gas pipeline | 6 | 6 | ||||||||||||||||||||||
Less: Accumulated amortization | (49 | ) | (48 | ) | ||||||||||||||||||||
Balance, net of amortization | $ | 161 | $ | 164 | ||||||||||||||||||||
The amount of non-cash property additions recognized for the years ended December 31, 2014, 2013, and 2012 was $528 million, $411 million, and $524 million, respectively. These amounts are comprised of construction-related accounts payable outstanding at each year end. Also, the amount of non-cash property additions associated with capitalized leases for the years ended December 31, 2014, 2013, and 2012 was $25 million, $107 million, and $14 million, respectively. | ||||||||||||||||||||||||
Acquisitions | Acquisitions | |||||||||||||||||||||||
Southern Power acquires generation assets as part of its overall growth strategy. Southern Power accounts for business acquisitions from non-affiliates as business combinations. Accordingly, Southern Power has included these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition was allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition was allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by Southern Power for successful or potential acquisitions have been expensed as incurred. | ||||||||||||||||||||||||
Depreciation, Depletion and Amortization | Depreciation and Amortization | |||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.1% in 2014, 3.3% in 2013, and 3.2% in 2012. Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and the FERC for the traditional operating companies. Accumulated depreciation for utility plant in service totaled $23.5 billion and $22.5 billion at December 31, 2014 and 2013, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Certain of Southern Power's generation assets are now depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. Cost, net of salvage value, of these assets is depreciated on an hours or starts units-of-production basis. The book value of plant-in-service as of December 31, 2014 that is depreciated on a units-of-production basis was approximately $470.2 million. | ||||||||||||||||||||||||
In 2009, the Georgia PSC approved an accounting order allowing Georgia Power to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of Georgia Power's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), Georgia Power amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $14 million is being amortized annually by Georgia Power over the three years ending December 31, 2016. See Note 3 under "Retail Regulatory Matters – Georgia Power – Rate Plans" for additional information. | ||||||||||||||||||||||||
Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives ranging from three to 25 years. Accumulated depreciation for other plant in service totaled $533 million and $513 million at December 31, 2014 and 2013, respectively. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal | |||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. Each traditional operating company has received accounting guidance from the various state PSCs allowing the continued accrual of other future retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The liability for AROs primarily relates to the decommissioning of the Southern Company system's nuclear facilities, Plants Farley, Hatch, and Vogtle. In addition, the Southern Company system has retirement obligations related to various landfill sites, ash ponds, asbestos removal, mine reclamation, and disposal of polychlorinated biphenyls in certain transformers. The Southern Company system also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, property associated with the Southern Company system's rail lines and natural gas pipelines, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the various state PSCs, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 2,018 | $ | 1,757 | ||||||||||||||||||||
Liabilities incurred | 18 | 6 | ||||||||||||||||||||||
Liabilities settled | (17 | ) | (16 | ) | ||||||||||||||||||||
Accretion | 102 | 97 | ||||||||||||||||||||||
Cash flow revisions | 80 | 174 | ||||||||||||||||||||||
Balance at end of year | $ | 2,201 | $ | 2,018 | ||||||||||||||||||||
The cash flow revisions in 2014 are primarily related to Alabama Power's and SEGCO's AROs associated with asbestos at their steam generation facilities. The cash flow revisions in 2013 are primarily related to revisions to the nuclear decommissioning ARO based on Alabama Power's updated decommissioning study and Georgia Power's updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the traditional operating companies' ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, Southern Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $860 million and ongoing post-closure care of approximately $140 million. Certain of the traditional operating companies have previously recorded AROs associated with ash ponds of $506 million, or $468 million on a nominal dollar basis, based on existing state requirements. During 2015, the traditional operating companies will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. Southern Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Nuclear Decommissioning | Nuclear Decommissioning | |||||||||||||||||||||||
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of Southern Company, Alabama Power, and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. | ||||||||||||||||||||||||
Southern Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. | ||||||||||||||||||||||||
The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2014 and 2013, approximately $51 million and $32 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $52 million and $33 million at December 31, 2014 and 2013, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows. | ||||||||||||||||||||||||
At December 31, 2014, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $886 million, debt securities of $638 million, and $19 million of other securities. At December 31, 2013, investment securities in the Funds totaled $1.5 billion, consisting of equity securities of $896 million, debt securities of $528 million, and $40 million of other securities. These amounts include the investment securities pledged to creditors and collateral received and exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases and the lending pool. | ||||||||||||||||||||||||
Sales of the securities held in the Funds resulted in cash proceeds of $913 million, $1.0 billion, and $1.0 billion in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $98 million, of which $2 million related to realized gains and $19 million related to unrealized gains and losses related to securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $181 million, of which $5 million related to realized gains and $119 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $137 million, of which $4 million related to realized gains and $75 million related to unrealized gains related to securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. | ||||||||||||||||||||||||
For Alabama Power, amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. | ||||||||||||||||||||||||
At December 31, 2014 and 2013, the accumulated provisions for decommissioning were as follows: | ||||||||||||||||||||||||
External Trust Funds | Internal Reserves | Total | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Plant Farley | $ | 754 | $ | 713 | $ | 21 | $ | 21 | $ | 775 | $ | 734 | ||||||||||||
Plant Hatch | 496 | 469 | — | — | 496 | 469 | ||||||||||||||||||
Plant Vogtle Units 1 and 2 | 293 | 277 | — | — | 293 | 277 | ||||||||||||||||||
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning as of December 31, 2014 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2012 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2: | ||||||||||||||||||||||||
Plant Farley | Plant Hatch | Plant Vogtle | ||||||||||||||||||||||
Units 1 and 2 | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2037 | 2034 | 2047 | |||||||||||||||||||||
Completion year | 2076 | 2068 | 2072 | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 1,362 | $ | 549 | $ | 453 | ||||||||||||||||||
Spent fuel management | — | 131 | 115 | |||||||||||||||||||||
Non-radiated structures | 80 | 51 | 76 | |||||||||||||||||||||
Total site study costs | $ | 1,442 | $ | 731 | $ | 644 | ||||||||||||||||||
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study, and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved Georgia Power's annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Georgia Power expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and 2.4% for Alabama Power and Georgia Power, respectively, and a trust earnings rate of 7.0% and 4.4% for Alabama Power and Georgia Power, respectively. | ||||||||||||||||||||||||
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction and Interest Capitalized | |||||||||||||||||||||||
In accordance with regulatory treatment, the traditional operating companies record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. Interest related to the construction of new facilities not included in the traditional operating companies' regulated rates is capitalized in accordance with standard interest capitalization requirements. AFUDC and interest capitalized, net of income taxes were 16.0%, 15.0%, and 8.2% of net income for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
Cash payments for interest totaled $732 million, $759 million, and $803 million in 2014, 2013, and 2012, respectively, net of amounts capitalized of $111 million, $92 million, and $83 million, respectively. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles | |||||||||||||||||||||||
Southern Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Reserves, Damages, and Recoveries | Storm Damage Reserves | |||||||||||||||||||||||
Each traditional operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and generally the cost of uninsured damages to its generation facilities and other property. In accordance with their respective state PSC orders, the traditional operating companies accrued $40 million in 2014 and $28 million in 2013. Alabama Power, Gulf Power, and Mississippi Power also have authority based on orders from their state PSCs to accrue certain additional amounts as circumstances warrant. In 2014 and 2013, there were no such additional accruals. See Note 3 under "Retail Regulatory Matters – Alabama Power – Natural Disaster Reserve" and "Retail Regulatory Matters – Georgia Power – Storm Damage Recovery" for additional information regarding Alabama Power's NDR and Georgia Power's deferred storm costs, respectively. | ||||||||||||||||||||||||
Leveraged Leases | Leveraged Leases | |||||||||||||||||||||||
Southern Company has several leveraged lease agreements, with original terms ranging up to 45 years, which relate to international and domestic energy generation, distribution, and transportation assets. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt related to these investments. The Company reviews all important lease assumptions at least annually, or more frequently if events or changes in circumstances indicate that a change in assumptions has occurred or may occur. These assumptions include the effective tax rate, the residual value, the credit quality of the lessees, and the timing of expected tax cash flows. | ||||||||||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | Materials and Supplies | |||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | Fuel Inventory | |||||||||||||||||||||||
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the traditional operating companies through fuel cost recovery rates approved by each state PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | Financial Instruments | |||||||||||||||||||||||
Southern Company and its subsidiaries use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Southern Company system's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional operating companies' fuel-hedging programs result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. At December 31, 2014, the amount included in accounts payable in the balance sheets that the Company has recognized for the obligation to return cash collateral arising from derivative instruments was immaterial. | ||||||||||||||||||||||||
Southern Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | Comprehensive Income | |||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges and marketable securities, certain changes in pension and other postretirement benefit plans, reclassifications for amounts included in net income, and dividends on preferred and preference stock of subsidiaries. | ||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
General | General | |||||||||||||||||||||||
Alabama Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Farley. | ||||||||||||||||||||||||
The equity method is used for subsidiaries in which the Company has significant influence but does not control and for variable interest entities (VIEs) where the Company has an equity investment, but is not the primary beneficiary. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Alabama PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | |||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | Affiliate Transactions | |||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $400 million, $340 million, and $340 million during 2014, 2013, and 2012, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business and operations. Costs for these services amounted to $234 million, $211 million, and $218 million during 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
The Company jointly owns Plant Greene County with Mississippi Power. The Company has an agreement with Mississippi Power under which the Company operates Plant Greene County, and Mississippi Power reimburses the Company for its proportionate share of non-fuel expenses, which were $13 million in 2014, $13 million in 2013, and $12 million in 2012. Also, Mississippi Power reimburses the Company for any direct fuel purchases delivered from one of the Company's transfer facilities, which were $34 million in 2014, $27 million in 2013, and $28 million in 2012. See Note 4 for additional information. | ||||||||||||||||||||||||
The Company has an agreement with Gulf Power under which the Company has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA. In 2009, Gulf Power entered into a PPA for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. The total cost committed by the Company related to the upgrades is approximately $85 million, of which approximately $29 million was spent in 2014. The transmission improvements were completed in 2014. The Company expects to recover a majority of these costs through a tariff with Gulf Power until 2023. The remainder of these costs will be recovered through normal rate mechanisms. | ||||||||||||||||||||||||
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014, 2013, or 2012. | ||||||||||||||||||||||||
Also, see Note 4 for information regarding the Company's ownership in a PPA and a gas pipeline ownership agreement with SEGCO. | ||||||||||||||||||||||||
The traditional operating companies, including the Company and Southern Power, may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities | |||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Deferred income tax charges | $ | 525 | $ | 519 | (a,k) | |||||||||||||||||||
Loss on reacquired debt | 80 | 86 | (b) | |||||||||||||||||||||
Vacation pay | 65 | 63 | (c,j) | |||||||||||||||||||||
Under/(over) recovered regulatory clause revenues | 57 | (18 | ) | (d) | ||||||||||||||||||||
Fuel-hedging losses | 53 | 8 | (e) | |||||||||||||||||||||
Other regulatory assets | 49 | 52 | (f) | |||||||||||||||||||||
Asset retirement obligations | (125 | ) | (132 | ) | (a) | |||||||||||||||||||
Other cost of removal obligations | (744 | ) | (828 | ) | (a) | |||||||||||||||||||
Deferred income tax credits | (72 | ) | (75 | ) | (a) | |||||||||||||||||||
Fuel-hedging gains | (1 | ) | (8 | ) | (e) | |||||||||||||||||||
Nuclear outage | 56 | 51 | (d) | |||||||||||||||||||||
Natural disaster reserve | (84 | ) | (96 | ) | (h) | |||||||||||||||||||
Other regulatory liabilities | (8 | ) | (11 | ) | (d,g) | |||||||||||||||||||
Retiree benefit plans | 882 | 461 | (i,j) | |||||||||||||||||||||
Regulatory deferrals | 13 | 20 | (l) | |||||||||||||||||||||
Nuclear fuel disposal fee | (8 | ) | — | (m) | ||||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 738 | $ | 92 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(b) | Recovered over the remaining life of the original issue, which may range up to 50 years. | |||||||||||||||||||||||
(c) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(d) | Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years. | |||||||||||||||||||||||
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||||||||||||||||||
(f) | Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. | |||||||||||||||||||||||
(g) | Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. | |||||||||||||||||||||||
(h) | Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. | |||||||||||||||||||||||
(i) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | |||||||||||||||||||||||
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(k) | Included in the deferred income tax charges are $18 million for 2014 and $20 million for 2013 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. | |||||||||||||||||||||||
(l) | Recorded and amortized as approved by the Alabama PSC for a period of five years. | |||||||||||||||||||||||
(m) | Recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The term of deferral is conditional upon resolution by the DOE. See Note 3 for additional information. | |||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Revenues | Revenues | |||||||||||||||||||||||
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company continuously monitors the under/over recovered balances and files for revised rates as required or when management deems appropriate, depending on the rate. See Note 3 under "Retail Regulatory Matters – Rate ECR" and "Retail Regulatory Matters – Rate CNP" for additional information. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | Fuel Costs | |||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel and a charge, based on nuclear generation, for the permanent disposal of spent nuclear fuel. | ||||||||||||||||||||||||
See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee Accounting Order" for additional information. | ||||||||||||||||||||||||
Income and Other Taxes | Income and Other Taxes | |||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | Property, Plant, and Equipment | |||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 11,670 | $ | 11,314 | ||||||||||||||||||||
Transmission | 3,579 | 3,287 | ||||||||||||||||||||||
Distribution | 6,196 | 5,934 | ||||||||||||||||||||||
General | 1,623 | 1,545 | ||||||||||||||||||||||
Plant acquisition adjustment | 12 | 12 | ||||||||||||||||||||||
Total plant in service | $ | 23,080 | $ | 22,092 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs, which are recorded in accordance with specific Alabama PSC orders. | ||||||||||||||||||||||||
Depreciation, Depletion and Amortization | Depreciation and Amortization | |||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2014 and 3.2% in 2013 and 2012. Depreciation studies are conducted periodically to update the composite rates and the information is provided to the Alabama PSC and the FERC. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. | ||||||||||||||||||||||||
In 2014, the Company submitted a depreciation study to the FERC and received authorization to use the recommended rates beginning January 2015. The study was also provided to the Alabama PSC. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal | |||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Alabama PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The liability for AROs primarily relates to the decommissioning of the Company's nuclear facility, Plant Farley. In addition, the Company has retirement obligations related to various landfill sites, underground storage tanks, asbestos removal, disposal of polychlorinated biphenyls in certain transformers, and disposal of sulfur hexafluoride gas in certain substation breakers. The Company also has identified retirement obligations related to certain transmission and distribution facilities and certain wireless communication towers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Alabama PSC, and are reflected in the balance sheets. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 730 | $ | 589 | ||||||||||||||||||||
Liabilities incurred | 1 | — | ||||||||||||||||||||||
Liabilities settled | (3 | ) | (1 | ) | ||||||||||||||||||||
Accretion | 45 | 40 | ||||||||||||||||||||||
Cash flow revisions | 56 | 102 | ||||||||||||||||||||||
Balance at end of year | $ | 829 | $ | 730 | ||||||||||||||||||||
The cash flow revisions in 2014 are primarily related to the Company's AROs associated with asbestos at its steam generation facilities. The cash flow revisions in 2013 are primarily related to revisions to the nuclear decommissioning ARO based on the Company's updated decommissioning study. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $311 million and ongoing post-closure care of approximately $49 million. The Company will record AROs for the estimated closure costs required under the CCR Rule during 2015. SEGCO, which is jointly owned with Georgia Power, will also record an ARO for ash ponds commonly used at Plant E.C. Gaston. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Nuclear Decommissioning | Nuclear Decommissioning | |||||||||||||||||||||||
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Alabama PSC, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. | ||||||||||||||||||||||||
The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. | ||||||||||||||||||||||||
At December 31, 2014, investment securities in the Funds totaled $754 million, consisting of equity securities of $583 million, debt securities of $163 million, and $8 million of other securities. At December 31, 2013, investment securities in the Funds totaled $713 million, consisting of equity securities of $566 million, debt securities of $131 million, and $16 million of other securities. These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases. | ||||||||||||||||||||||||
Sales of the securities held in the Funds resulted in cash proceeds of $244 million, $279 million, and $193 million in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $54 million, of which $2 million related to realized gains and $19 million related to unrealized gains related to securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $120 million, of which $5 million related to realized gains and $85 million related to unrealized gains related to securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $70 million, of which $4 million related to realized gains and $50 million related to unrealized losses related to securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. | ||||||||||||||||||||||||
Amounts previously recorded in internal reserves are being transferred into the Funds over periods approved by the Alabama PSC. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed a plan with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. | ||||||||||||||||||||||||
At December 31, the accumulated provisions for decommissioning were as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
External trust funds | $ | 754 | $ | 713 | ||||||||||||||||||||
Internal reserves | 21 | 21 | ||||||||||||||||||||||
Total | $ | 775 | 734 | |||||||||||||||||||||
Site study costs is the estimate to decommission a facility as of the site study year. The estimated costs of decommissioning as of December 31, 2014 based on the most current study performed in 2013 for Plant Farley are as follows: | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2037 | |||||||||||||||||||||||
Completion year | 2076 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 1,362 | ||||||||||||||||||||||
Non-radiated structures | 80 | |||||||||||||||||||||||
Total site study costs | $ | 1,442 | ||||||||||||||||||||||
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. | ||||||||||||||||||||||||
For ratemaking purposes, the Company's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be conducted in 2018. | ||||||||||||||||||||||||
Amounts previously contributed to the Funds are currently projected to be adequate to meet the decommissioning obligations. The Company will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction | |||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. All current construction costs are included in retail rates. The AFUDC composite rate as of December 31 was 8.8% in 2014, 9.1% in 2013, and 9.4% in 2012. AFUDC, net of income taxes, as a percent of net income after dividends on preferred and preference stock was 7.9% in 2014, 5.4% in 2013, and 3.3% in 2012. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles | |||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | Materials and Supplies | |||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | Fuel Inventory | |||||||||||||||||||||||
Fuel inventory includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through energy cost recovery rates approved by the Alabama PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | Financial Instruments | |||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Alabama PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. If any, immaterial ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | Comprehensive Income | |||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Variable Interest Entities | Variable Interest Entities | |||||||||||||||||||||||
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. | ||||||||||||||||||||||||
The Company has established a wholly-owned trust to issue preferred securities. See Note 6 under "Long-Term Debt Payable to an Affiliated Trust" for additional information. However, the Company is not considered the primary beneficiary of the trust. Therefore, the investment in the trust is reflected as other investments, and the related loan from the trust is reflected as long-term debt in the balance sheets. | ||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
General | General | |||||||||||||||||||||||
Georgia Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public, and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including the Company's Plant Hatch and Plant Vogtle. | ||||||||||||||||||||||||
The equity method is used for subsidiaries in which the Company has significant influence but does not control. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Georgia PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | |||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | Affiliate Transactions | |||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $555 million in 2014, $504 million in 2013, and $540 million in 2012. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has an agreement with Southern Nuclear under which the following nuclear-related services are rendered to the Company at cost: general executive and advisory services, general operations, management and technical services, administrative services including procurement, accounting, employee relations, systems and procedures services, strategic planning and budgeting services, and other services with respect to business, operations, and construction management. Costs for these services amounted to $643 million in 2014, $555 million in 2013, and $574 million in 2012. | ||||||||||||||||||||||||
The Company has entered into several PPAs with Southern Power for capacity and energy. Expenses associated with these PPAs were $144 million, $136 million, and $147 million in 2014, 2013, and 2012, respectively. Additionally, the Company had $15 million of prepaid capacity expenses included in deferred charges and other assets in the balance sheets at December 31, 2014 and 2013. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
The Company has a joint ownership agreement with Gulf Power under which Gulf Power owns a 25% portion of Plant Scherer Unit 3. Under this agreement, the Company operates Plant Scherer Unit 3 and Gulf Power reimburses the Company for its 25% proportionate share of the related non-fuel expenses, which were $9 million in 2014, $10 million in 2013, and $7 million in 2012. See Note 4 for additional information. | ||||||||||||||||||||||||
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014, 2013, or 2012. | ||||||||||||||||||||||||
The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities | |||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Retiree benefit plans | $ | 1,325 | $ | 691 | (a, j) | |||||||||||||||||||
Deferred income tax charges | 668 | 684 | (b, j) | |||||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 34 | 38 | (c) | |||||||||||||||||||||
Loss on reacquired debt | 163 | 181 | (d, j) | |||||||||||||||||||||
Asset retirement obligations | 108 | 137 | (b, j) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 29 | 22 | (e, j) | |||||||||||||||||||||
Vacation pay | 91 | 88 | (f, j) | |||||||||||||||||||||
Building lease | 31 | 37 | (g, j) | |||||||||||||||||||||
Cancelled construction projects | 67 | 70 | (h) | |||||||||||||||||||||
Remaining net book value of retired units | 25 | 28 | (i) | |||||||||||||||||||||
Storm damage reserves | 98 | 37 | (c) | |||||||||||||||||||||
Other regulatory assets | 63 | 49 | (c) | |||||||||||||||||||||
Other cost of removal obligations | (60 | ) | (58 | ) | (b) | |||||||||||||||||||
Deferred income tax credits | (106 | ) | (112 | ) | (b, j) | |||||||||||||||||||
Other regulatory liabilities | (7 | ) | (6 | ) | (e, j) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 2,529 | $ | 1,886 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the remaining two-year period of January 2015 through December 2016 in accordance with the Company's 2013 ARP. | |||||||||||||||||||||||
(c) | Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding eight years. | |||||||||||||||||||||||
(d) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 38 years. | |||||||||||||||||||||||
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism. | |||||||||||||||||||||||
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(g) | See Note 6 under "Capital Leases." Recovered over the remaining life of the building through 2020. | |||||||||||||||||||||||
(h) | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||||||||||||||||||
(i) | Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2022. | |||||||||||||||||||||||
(j) | Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Revenues | Revenues | |||||||||||||||||||||||
Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amount billable under the contract terms. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between the actual recoverable costs and amounts billed in current regulated rates. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | Fuel Costs | |||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense also includes the amortization of the cost of nuclear fuel. See Note 3 under "Retail Regulatory Matters – Nuclear Waste Fund Fee" for additional information. | ||||||||||||||||||||||||
Income and Other Taxes | Income and Other Taxes | |||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
Federal ITCs utilized are deferred and amortized to income as a credit to reduce depreciation over the average life of the related property. State ITCs are recognized in the period in which the credits are claimed on the state income tax return. A portion of the ITCs available to reduce income taxes payable was not utilized currently and will be carried forward and utilized in future years. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | Property, Plant, and Equipment | |||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the cost of equity and debt funds used during construction. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 15,201 | $ | 14,872 | ||||||||||||||||||||
Transmission | 5,086 | 4,859 | ||||||||||||||||||||||
Distribution | 8,913 | 8,620 | ||||||||||||||||||||||
General | 1,855 | 1,753 | ||||||||||||||||||||||
Plant acquisition adjustment | 28 | 28 | ||||||||||||||||||||||
Total plant in service | $ | 31,083 | $ | 30,132 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of certain generating plant maintenance costs. As mandated by the Georgia PSC, the Company defers and amortizes nuclear refueling outage costs over the unit's operating cycle. The refueling cycles are 18 and 24 months for Plant Vogtle Units 1 and 2 and Plant Hatch Units 1 and 2, respectively. | ||||||||||||||||||||||||
Depreciation, Depletion and Amortization | Depreciation and Amortization | |||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 2.7% in 2014, 3.0% in 2013, and 2.9% in 2012. Depreciation studies are conducted periodically to update the composite rates that are approved by the Georgia PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. | ||||||||||||||||||||||||
In 2009, the Georgia PSC approved an accounting order allowing the Company to amortize a portion of its regulatory liability related to other cost of removal obligations. Under the terms of the Company's Alternate Rate Plan for the years 2011 through 2013 (2010 ARP), the Company amortized approximately $31 million annually of the remaining regulatory liability related to other cost of removal obligations over the three years ended December 31, 2013. Under the terms of the 2013 ARP, an additional $14 million is being amortized annually over the three years ending December 31, 2016. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal | |||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Georgia PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The ARO liability relates to the decommissioning of the Company's nuclear facilities, which include the Company's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2, as well as various landfill sites, ash ponds, underground storage tanks, and asbestos removal. The Company also has identified retirement obligations related to certain transmission and distribution facilities, including the disposal of polychlorinated biphenyls in certain transformers; leasehold improvements; equipment on customer property; and property associated with the Company's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the Georgia PSC. See "Nuclear Decommissioning" herein for additional information on amounts included in rates. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 1,222 | $ | 1,105 | ||||||||||||||||||||
Liabilities incurred | 9 | 2 | ||||||||||||||||||||||
Liabilities settled | (12 | ) | (13 | ) | ||||||||||||||||||||
Accretion | 53 | 55 | ||||||||||||||||||||||
Cash flow revisions | (17 | ) | 73 | |||||||||||||||||||||
Balance at end of year | $ | 1,255 | $ | 1,222 | ||||||||||||||||||||
The 2014 decrease in cash flow revisions is primarily related to settled AROs for asbestos remediation. The 2013 increase in cash flow revisions is related to updated estimates for ash ponds in connection with the retirement of certain coal-fired generating units and revisions to the nuclear decommissioning AROs based on the latest decommissioning study. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $390 million and ongoing post-closure care of approximately $62 million. The Company has previously recorded AROs associated with ash ponds of $500 million, or $458 million on a nominal dollar basis, based on existing state requirements. During 2015, the Company will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Nuclear Decommissioning | Nuclear Decommissioning | |||||||||||||||||||||||
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. The Company has external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and the Georgia PSC, as well as the IRS. While the Company is allowed to prescribe an overall investment policy to the Funds' managers, the Company and its affiliates are not allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third party managers with oversight by the management of the Company. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities. | ||||||||||||||||||||||||
The Company records the investment securities held in the Funds at fair value, as disclosed in Note 10, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis. | ||||||||||||||||||||||||
The Funds participate in a securities lending program through the managers of the Funds. Under this program, the Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. As of December 31, 2014 and 2013, approximately $51 million and $32 million, respectively, of the fair market value of the Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $52 million and $33 million at December 31, 2014 and 2013, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows. | ||||||||||||||||||||||||
At December 31, 2014, investment securities in the Funds totaled $789 million, consisting of equity securities of $303 million, debt securities of $475 million, and $11 million of other securities. At December 31, 2013, investment securities in the Funds totaled $751 million, consisting of equity securities of $330 million, debt securities of $397 million, and $24 million of other securities. These amounts include the investment securities pledged to creditors and collateral received, and exclude receivables related to investment income and pending investment sales, and payables related to pending investment purchases and the lending pool. | ||||||||||||||||||||||||
Sales of the securities held in the Funds resulted in cash proceeds of $669 million, $705 million, and $850 million in 2014, 2013, and 2012, respectively, all of which were reinvested. For 2014, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $44 million, of which an immaterial amount related to unrealized gains and losses on securities held in the Funds at December 31, 2014. For 2013, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $61 million, of which $34 million related to unrealized gains on securities held in the Funds at December 31, 2013. For 2012, fair value increases, including reinvested interest and dividends and excluding the Funds' expenses, were $67 million, of which $25 million related to unrealized losses on securities held in the Funds at December 31, 2012. While the investment securities held in the Funds are reported as trading securities, the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired. | ||||||||||||||||||||||||
The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. The Company has filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC. | ||||||||||||||||||||||||
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning are based on the most current study performed in 2012. The site study costs and external trust funds for decommissioning as of December 31, 2014 based on the Company's ownership interests were as follows: | ||||||||||||||||||||||||
Plant Hatch | Plant Vogtle | |||||||||||||||||||||||
Units 1 and 2 | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2034 | 2047 | ||||||||||||||||||||||
Completion year | 2068 | 2072 | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 549 | $ | 453 | ||||||||||||||||||||
Spent fuel management | 131 | 115 | ||||||||||||||||||||||
Non-radiated structures | 51 | 76 | ||||||||||||||||||||||
Total site study costs | $ | 731 | $ | 644 | ||||||||||||||||||||
External trust funds | $ | 496 | $ | 293 | ||||||||||||||||||||
For ratemaking purposes, the Company's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2012. Under the 2013 ARP, the Georgia PSC approved annual decommissioning cost through 2016 for ratemaking of $4 million and $2 million for Plant Hatch and Plant Vogtle Units 1 and 2, respectively. Significant assumptions used to determine the costs for ratemaking include an estimated inflation rate of 2.4% and an estimated trust earnings rate of 4.4%. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for nuclear decommissioning costs. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction | |||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. For the years 2014, 2013, and 2012, the average AFUDC rates were 5.6%, 5.3%, and 6.8%, respectively, and AFUDC capitalized was $62 million, $44 million, and $75 million, respectively. AFUDC, net of income taxes, was 4.6%, 3.3%, and 5.7% of net income after dividends on preferred and preference stock for 2014, 2013, and 2012, respectively. See Note 3 under "Retail Regulatory Matters – Nuclear Construction" for additional information on the inclusion of construction costs related to Plant Vogtle Units 3 and 4 in rate base effective January 1, 2011. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles | |||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Reserves, Damages, and Recoveries | Storm Damage Recovery | |||||||||||||||||||||||
The Company defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2014, the Company is accruing $30 million annually under the 2013 ARP that is recoverable through base rates. As of December 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $98 million and $37 million, respectively, with approximately $30 million included in other regulatory assets, current for both years and approximately $68 million and $7 million included in other regulatory assets, deferred, respectively. The Company expects the Georgia PSC to periodically review and adjust, if necessary, the amounts collected in rates for storm damage costs. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on the Company's financial statements. | ||||||||||||||||||||||||
Environmental Remediation Recovery | ||||||||||||||||||||||||
The Company maintains a reserve for environmental remediation as mandated by the Georgia PSC. In December 2013, the Georgia PSC approved the 2013 ARP including the recovery of approximately $2 million annually through the environmental compliance cost recovery (ECCR) tariff from 2014 through 2016. The Company recovered approximately $3 million annually through the ECCR tariff from 2011 through 2013 under the 2010 ARP. The Company recognizes a liability for environmental remediation costs only when it determines a loss is probable and reduces the reserve as expenditures are incurred. Any difference between the liabilities accrued and cost recovered through rates is deferred as a regulatory asset or liability. The annual recovery amount is expected to be reviewed by the Georgia PSC and adjusted in future regulatory proceedings. As a result of this regulatory treatment, environmental remediation liabilities generally are not expected to have a material impact on the Company's financial statements. As of December 31, 2014, the balance of the environmental remediation liability was $22 million, with approximately $2 million included in other regulatory assets, current and approximately $14 million included as other regulatory assets, deferred. See Note 3 under "Environmental Matters – Environmental Remediation" for additional information. | ||||||||||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | Materials and Supplies | |||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | Fuel Inventory | |||||||||||||||||||||||
Fuel inventory includes the average cost of coal, natural gas, and oil, as well as transportation and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates approved by the Georgia PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | Financial Instruments | |||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 10 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Georgia PSC-approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 11 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | Comprehensive Income | |||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
General | General | |||||||||||||||||||||||
Gulf Power Company (the Company) is a wholly-owned subsidiary of The Southern Company (Southern Company), which is the parent company of four traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – the Company, Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in northwest Florida and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
The equity method is used for entities in which the Company has significant influence but does not control. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Florida PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | |||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | Affiliate Transactions | |||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $79.6 million, $78.4 million, and $95.9 million during 2014, 2013, and 2012, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has operating agreements with Georgia Power and Mississippi Power under which the Company owns a portion of Plant Scherer and Plant Daniel, respectively. Georgia Power operates Plant Scherer and Mississippi Power operates Plant Daniel. The Company reimbursed Georgia Power $8.7 million, $10.2 million, and $6.9 million and Mississippi Power $30.5 million, $16.5 million, and $21.1 million in 2014, 2013, and 2012, respectively, for its proportionate share of related expenses. See Note 4 and Note 7 under "Operating Leases" for additional information. | ||||||||||||||||||||||||
The Company entered into a PPA with Southern Power for approximately 292 MWs annually from June 2009 through May 2014. Purchased power expenses associated with the PPA were $1.8 million, $14.2 million, and $14.7 million in 2014, 2013, and 2012, respectively, and fuel costs associated with the PPA were $1.7 million, $0.8 million, and $2.6 million in 2014, 2013, and 2012, respectively. These costs were approved for recovery by the Florida PSC through the Company's fuel and purchased power capacity cost recovery clauses. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
The Company had an agreement with Georgia Power under the transmission facility cost allocation tariff for delivery of power from the Company's resources in the state of Georgia. The Company reimbursed Georgia Power $1.0 million in 2014 and $2.4 million in each of the years 2013 and 2012 for its share of related expenses. | ||||||||||||||||||||||||
The Company has an agreement with Alabama Power under which Alabama Power has made transmission system upgrades to ensure firm delivery of energy under a non-affiliate PPA, which was entered into in 2009 for the capacity and energy from a combined cycle plant located in Autauga County, Alabama. Revenue requirement obligations to Alabama Power for these upgrades are estimated to be $132.0 million for the entire project. These costs began in July 2012 and will continue through 2023. The Company reimbursed Alabama Power $11.9 million, $7.9 million, and $3.0 million in 2014, 2013, and 2012, respectively, for the revenue requirements. These costs have been approved for recovery by the Florida PSC through the Company's purchased power capacity cost recovery clause and by the FERC in the transmission facilities cost allocation tariff. | ||||||||||||||||||||||||
The Company provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014, 2013, or 2012. | ||||||||||||||||||||||||
The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities | |||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Deferred income tax charges | $ | 53,234 | $ | 47,573 | (a) | |||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 3,024 | 3,351 | (b) | |||||||||||||||||||||
Asset retirement obligations | (5,087 | ) | (6,089 | ) | (a,j) | |||||||||||||||||||
Other cost of removal obligations | (242,997 | ) | (228,148 | ) | (a) | |||||||||||||||||||
Regulatory asset, offset to other cost of removal | 8,410 | — | (m) | |||||||||||||||||||||
Deferred income tax credits | (3,872 | ) | (5,238 | ) | (a) | |||||||||||||||||||
Loss on reacquired debt | 15,991 | 16,565 | (c) | |||||||||||||||||||||
Vacation pay | 10,006 | 9,521 | (d,j) | |||||||||||||||||||||
Under recovered regulatory clause revenues | 52,619 | 45,191 | (e) | |||||||||||||||||||||
Property damage reserve | (35,111 | ) | (35,380 | ) | (f) | |||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 73,474 | 17,043 | (g,j) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) gains | (112 | ) | (6,962 | ) | (g,j) | |||||||||||||||||||
PPA charges | 185,065 | 180,149 | (j,k) | |||||||||||||||||||||
Other regulatory assets | 9,753 | 12,772 | (l) | |||||||||||||||||||||
Environmental remediation | 48,271 | 50,384 | (h,j) | |||||||||||||||||||||
Other regulatory liabilities | (649 | ) | (8,804 | ) | (f,j) | |||||||||||||||||||
Retiree benefit plans, net | 147,625 | 68,296 | (i,j) | |||||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 319,644 | $ | 160,224 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(b) | Recovered and amortized over periods not exceeding 14 years. | |||||||||||||||||||||||
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years. | |||||||||||||||||||||||
(d) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(e) | Recorded and recovered or amortized as approved by the Florida PSC, generally within one year. | |||||||||||||||||||||||
(f) | Recorded and recovered or amortized as approved by the Florida PSC. | |||||||||||||||||||||||
(g) | Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. | |||||||||||||||||||||||
(h) | Recovered through the environmental cost recovery clause when the remediation is performed. | |||||||||||||||||||||||
(i) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||||||||||||||||||
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(k) | Recovered over the life of the PPA for periods up to nine years. | |||||||||||||||||||||||
(l) | Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects. | |||||||||||||||||||||||
(m) Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013. See Note 3 for additional information. | ||||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income or reclassify to accumulated OCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Revenues | Revenues | |||||||||||||||||||||||
Wholesale capacity revenues are generally recognized on a levelized basis over the appropriate contract period. Energy and other revenues are recognized as services are provided. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Electric rates for the Company include provisions to adjust billings for fluctuations in fuel costs, the energy component of purchased power costs, and certain other costs. The Company continuously monitors the over or under recovered fuel cost balance in light of the inherent variability in fuel costs. The Company is required to notify the Florida PSC if the projected fuel cost over or under recovery is expected to exceed 10% of the projected fuel revenue applicable for the period and indicate if an adjustment to the fuel cost recovery factor is being requested. The Company has similar retail cost recovery clauses for energy conservation costs, purchased power capacity costs, and environmental compliance costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. Annually, the Company petitions for recovery of projected costs including any true-up amounts from prior periods, and approved rates are implemented each January. See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
Fuel Costs | Fuel Costs | |||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. | ||||||||||||||||||||||||
Income and Other Taxes | Income and Other Taxes | |||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal ITCs utilized are deferred and amortized to income over the average life of the related property and state ITCs are recognized in the period in which the credit is claimed on the state income tax return. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of income. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | Property, Plant, and Equipment | |||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Generation | $ | 2,637,817 | $ | 2,607,166 | ||||||||||||||||||||
Transmission | 515,754 | 473,378 | ||||||||||||||||||||||
Distribution | 1,156,872 | 1,117,024 | ||||||||||||||||||||||
General | 182,734 | 164,065 | ||||||||||||||||||||||
Plant acquisition adjustment | 1,776 | 2,031 | ||||||||||||||||||||||
Total plant in service | $ | 4,494,953 | $ | 4,363,664 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed. | ||||||||||||||||||||||||
Depreciation, Depletion and Amortization | Depreciation and Amortization | |||||||||||||||||||||||
Depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates, which approximated 3.6% in 2014, 2013, and 2012. Depreciation studies are conducted periodically to update the composite rates. These studies are approved by the Florida PSC and the FERC. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. As authorized by the Florida PSC in the settlement agreement approved in December 2013 (Settlement Agreement), the Company is allowed to reduce depreciation expense and record a regulatory asset in an aggregate amount up to $62.5 million between January 2014 and June 2017. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional information. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal | |||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received an order from the Florida PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The liability for AROs primarily relates to the Company's combustion turbines at its Pea Ridge facility, various landfill sites, a barge unloading dock, asbestos removal, ash ponds, and disposal of polychlorinated biphenyls in certain transformers. The Company also has identified retirement obligations related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of income allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Florida PSC, and are reflected in the balance sheets. | ||||||||||||||||||||||||
Details of the AROs included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 16,184 | $ | 16,055 | ||||||||||||||||||||
Liabilities incurred | — | 518 | ||||||||||||||||||||||
Liabilities settled | (32 | ) | (1,913 | ) | ||||||||||||||||||||
Accretion | 718 | 751 | ||||||||||||||||||||||
Cash flow revisions | (159 | ) | 773 | |||||||||||||||||||||
Balance at end of year | $ | 16,711 | $ | 16,184 | ||||||||||||||||||||
The 2014 cash flow revisions are associated with asbestos and ash ponds at the Company's steam generation facilities. The 2013 cash flow revisions are associated with asbestos and an unloading dock at its generation facilities. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $62 million and ongoing post-closure care of approximately $11 million. The Company has previously recorded AROs associated with ash ponds of $6 million, or $11 million on a nominal dollar basis, based on existing state requirements. During 2015, the Company will record AROs for any incremental estimated closure costs resulting from acceleration in the timing of any currently planned closures and for differences between existing state requirements and the requirements of the CCR Rule. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction | |||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in calculating taxable income. The average annual AFUDC rate was 5.73% for 2014, 6.26% for 2013, and 6.72% for 2012. AFUDC, net of income taxes, as a percentage of net income after dividends on preference stock was 10.93%, 6.87%, and 5.36% for 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles | |||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Reserves, Damages, and Recoveries | Property Damage Reserve | |||||||||||||||||||||||
The Company accrues for the cost of repairing damages from major storms and other uninsured property damages, including uninsured damages to transmission and distribution facilities, generation facilities, and other property. The costs of such damage are charged to the reserve. The Florida PSC approved annual accrual to the property damage reserve is $3.5 million, with a target level for the reserve between $48.0 million and $55.0 million. The Florida PSC also authorized the Company to make additional accruals above the $3.5 million at the Company's discretion. The Company accrued total expenses of $3.5 million in each of 2014, 2013, and 2012. As of December 31, 2014 and 2013, the balance in the Company's property damage reserve totaled approximately $35.7 million and $35.4 million, respectively, which is included in deferred liabilities in the balance sheets. | ||||||||||||||||||||||||
When the property damage reserve is inadequate to cover the cost of major storms, the Florida PSC can authorize a storm cost recovery surcharge to be applied to customer bills. In December 2013, the Florida PSC approved the Settlement Agreement that, among other things, provides for recovery of costs associated with any tropical systems named by the National Hurricane Center through the initiation of a storm surcharge. The storm surcharge will begin, on an interim basis, 60 days following the filing of a cost recovery petition. The storm surcharge generally may not exceed $4.00/1,000 KWHs on monthly residential bills in aggregate for a calendar year. This limitation does not apply if the Company incurs in excess of $100 million in storm recovery costs that qualify for recovery in a given calendar year. This threshold amount is inclusive of the amount necessary to replenish the storm reserve to the level that existed as of December 31, 2013. See Note 3 herein under "Retail Regulatory Matters – Retail Base Rate Case" for additional details of the Settlement Agreement. | ||||||||||||||||||||||||
Injuries and Damages Reserve | ||||||||||||||||||||||||
The Company is subject to claims and lawsuits arising in the ordinary course of business. As permitted by the Florida PSC, the Company accrues for the uninsured costs of injuries and damages by charges to income amounting to $1.6 million annually. The Florida PSC has also given the Company the flexibility to increase its annual accrual above $1.6 million to the extent the balance in the reserve does not exceed $2.0 million and to defer expense recognition of liabilities greater than the balance in the reserve. The cost of settling claims is charged to the reserve. The injuries and damages reserve was $4.0 million and $3.6 million at December 31, 2014 and 2013, respectively. For 2014, $1.6 million and $2.4 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. For 2013, $1.6 million and $2.0 million are included in current liabilities and deferred credits and other liabilities in the balance sheets, respectively. There were no liabilities in excess of the reserve balance at December 31, 2014 or 2013. | ||||||||||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | Materials and Supplies | |||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | Fuel Inventory | |||||||||||||||||||||||
Fuel inventory includes the average cost of oil, natural gas, coal, transportation, and emissions allowances. Fuel is charged to inventory when purchased and then expensed, at weighted average cost, as used. Fuel expense and emissions allowance costs are recovered by the Company through the fuel cost recovery and environmental cost recovery rates, respectively, approved annually by the Florida PSC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | Financial Instruments | |||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the Florida PSC approved fuel-hedging program result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. See Note 10 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | Comprehensive Income | |||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
General | General | |||||||||||||||||||||||
Mississippi Power Company (the Company) is a wholly owned subsidiary of The Southern Company (Southern Company), which is the parent company of the Company and three other traditional operating companies, as well as Southern Power, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and the Company – are vertically integrated utilities providing electric service in four Southeastern states. The Company operates as a vertically integrated utility providing electricity to retail customers in southeast Mississippi and to wholesale customers in the Southeast. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
The Company is subject to regulation by the FERC and the Mississippi PSC. The Company follows GAAP in the U.S. and complies with the accounting policies and practices prescribed by its regulatory commissions. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | |||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | Affiliate Transactions | |||||||||||||||||||||||
The Company has an agreement with SCS under which the following services are rendered to the Company at direct or allocated cost: general and design engineering, operations, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, and other services with respect to business and operations, construction management, and power pool transactions. Costs for these services amounted to $259.0 million, $205.0 million, and $212.7 million during 2014, 2013, and 2012, respectively. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has an agreement with Alabama Power under which the Company owns a portion of Greene County Steam Plant. Alabama Power operates Greene County Steam Plant, and the Company reimburses Alabama Power for its proportionate share of non-fuel expenditures and costs, which totaled $13.4 million, $12.5 million, and $11.7 million in 2014, 2013, and 2012, respectively. Also, the Company reimburses Alabama Power for any direct fuel purchases delivered from an Alabama Power transfer facility, which were $34.5 million, $27.1 million, and $28.1 million in 2014, 2013, and 2012, respectively. The Company also has an agreement with Gulf Power under which Gulf Power owns a portion of Plant Daniel. The Company operates Plant Daniel, and Gulf Power reimburses the Company for its proportionate share of all associated expenditures and costs, which totaled $30.5 million, $16.5 million, and $21.2 million in 2014, 2013, and 2012, respectively. See Note 4 for additional information. | ||||||||||||||||||||||||
The Company also provides incidental services to and receives such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the Company neither provided nor received any material services to or from affiliates in 2014 or 2013. The Company received storm assistance from other Southern Company subsidiaries totaling $2.0 million in 2012. | ||||||||||||||||||||||||
The traditional operating companies, including the Company, and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS, as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 7 under "Fuel and Purchased Power Agreements" for additional information. | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities | |||||||||||||||||||||||
The Company is subject to the provisions of the Financial Accounting Standards Board in accounting for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process. | ||||||||||||||||||||||||
Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | ||||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Retiree benefit plans – regulatory assets | $ | 169,317 | $ | 82,799 | (a,g) | |||||||||||||||||||
Property damage | (61,648 | ) | (60,092 | ) | (i) | |||||||||||||||||||
Deferred income tax charges | 222,599 | 140,185 | (c) | |||||||||||||||||||||
Property tax | 27,680 | 31,206 | (d) | |||||||||||||||||||||
Vacation pay | 11,172 | 10,214 | (e,g) | |||||||||||||||||||||
Loss on reacquired debt | 8,542 | 9,178 | (k) | |||||||||||||||||||||
Plant Daniel Units 3 and 4 regulatory assets | 23,013 | 18,821 | (j) | |||||||||||||||||||||
Other regulatory assets | 16,270 | 5,415 | (b) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 46,631 | 10,340 | (f,g) | |||||||||||||||||||||
Asset retirement obligations | 10,845 | 8,918 | (c) | |||||||||||||||||||||
Deferred income tax credits | (9,370 | ) | (10,191 | ) | (c) | |||||||||||||||||||
Other cost of removal obligations | (165,999 | ) | (156,683 | ) | (c) | |||||||||||||||||||
Kemper IGCC regulatory assets | 147,689 | 75,873 | (h) | |||||||||||||||||||||
Mirror CWIP / Kemper regulatory deferral | (270,779 | ) | (90,524 | ) | (h) | |||||||||||||||||||
Other regulatory liabilities | (4,198 | ) | (8,855 | ) | (b) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 171,764 | $ | 66,604 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Recorded and recovered (amortized) as approved by the Mississippi PSC. | |||||||||||||||||||||||
(c) | Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(d) | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. | |||||||||||||||||||||||
(e) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(f) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the ECM. | |||||||||||||||||||||||
(g) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(h) | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||||||||||||||
(i) | For additional information, see Note 1 under "Provision for Property Damage." | |||||||||||||||||||||||
(j) | Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. | |||||||||||||||||||||||
(k) | Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years. | |||||||||||||||||||||||
In the event that a portion of the Company's operations is no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income any regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Government Grants | Government Grants | |||||||||||||||||||||||
In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270.0 million of the Kemper IGCC through the DOE Grants funds. Through December 31, 2014, the Company has received grant funds of $245.3 million, used for the construction of the Kemper IGCC, which is reflected in the Company's financial statements as a reduction to the Kemper IGCC capital costs. An additional $25 million is expected to be received for its initial operation. See Note 3 under "Kemper IGCC Schedule and Cost Estimate" for additional information. | ||||||||||||||||||||||||
Revenues | Revenues | |||||||||||||||||||||||
Energy and other revenues are recognized as services are provided. Wholesale capacity revenues from long-term contracts are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract period. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. The Company's retail and wholesale rates include provisions to adjust billings for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Retail rates also include provisions to adjust billings for fluctuations in costs for ad valorem taxes and certain qualifying environmental costs. Revenues are adjusted for differences between these actual costs and projected amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered or returned to customers through adjustments to the billing factors. The Company is required to file with the Mississippi PSC for an adjustment to the fuel cost recovery, ad valorem, and environmental factors annually. | ||||||||||||||||||||||||
The Company serves long-term contracts with rural electric cooperative associations and municipalities located in southeastern Mississippi under cost-based MRA electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 21.9% of the Company's total operating revenues in 2014 and are largely subject to rolling 10-year cancellation notices. | ||||||||||||||||||||||||
The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 1% of revenues. | ||||||||||||||||||||||||
See Note 3 under "Retail Regulatory Matters" for additional information. | ||||||||||||||||||||||||
Fuel Costs | Fuel Costs | |||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. Fuel costs also include gains and/or losses from fuel-hedging programs as approved by the Mississippi PSC. | ||||||||||||||||||||||||
Income and Other Taxes | Income and Other Taxes | |||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. ITCs utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented net on the statements of operations. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | Property, Plant, and Equipment | |||||||||||||||||||||||
Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction for projects where recovery of CWIP is not allowed in rates. | ||||||||||||||||||||||||
The Company's property, plant, and equipment in service consisted of the following at December 31: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Generation | $ | 2,293,511 | $ | 1,475,264 | ||||||||||||||||||||
Transmission | 664,618 | 633,903 | ||||||||||||||||||||||
Distribution | 853,835 | 828,470 | ||||||||||||||||||||||
General | 484,711 | 439,721 | ||||||||||||||||||||||
Plant acquisition adjustment | 81,412 | 81,412 | ||||||||||||||||||||||
Total plant in service | $ | 4,378,087 | $ | 3,458,770 | ||||||||||||||||||||
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses except for all costs associated with operating and maintaining the Kemper IGCC assets already placed in service and a portion of the railway track maintenance costs, which are charged to fuel stock and recovered through the Company's fuel clause or charged to regulatory assets to be recovered through rates over the life of the assets starting after the Kemper plant is placed in service. In addition, the cost of maintenance, repairs, and replacement of minor items of property for Kemper IGCC assets in service, excluding the lignite mine, are deferred in regulatory assets. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Depreciation, Depletion and Amortization | Depreciation, Depletion, and Amortization | |||||||||||||||||||||||
Depreciation of the original cost of plant in service is provided primarily by using composite straight-line rates, which approximated 3.3% in 2014, 3.4% in 2013, and 3.5% in 2012. Depreciation studies are conducted periodically to update the composite rates. When property subject to depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. Minor items of property included in the original cost of the plant are retired when the related property unit is retired. Depreciation includes an amount for the expected cost of removal of facilities. | ||||||||||||||||||||||||
In January 2012, the Mississippi PSC issued an order allowing the Company to defer in a regulatory asset the difference between the revenue requirement under the purchase option of Plant Daniel Units 3 and 4 and the revenue requirement assuming operating lease accounting treatment for the extended term. The regulatory asset will be deferred for a 10-year period ending October 2021. At the conclusion of the deferral period, the unamortized deferral balance will be amortized into rates over the remaining life of the units. | ||||||||||||||||||||||||
The Kemper IGCC will be fueled by locally mined lignite (an abundant, lower heating value coal) from a mine owned by the Company and situated adjacent to the Kemper IGCC. The mine, operated by North American Coal Corporation, started commercial operation in June 2013. Depreciation associated with fixed assets, amortization associated with rolling stock, and depletion associated with minerals and minerals rights is recognized and charged to fuel stock and is expected to be recovered through the Company’s fuel clause. Depreciation associated with in-service Kemper IGCC-related assets has been deferred as a regulatory asset to be recovered over the life of the Kemper IGCC. | ||||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Asset Retirement Obligations and Other Costs of Removal | |||||||||||||||||||||||
Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. The Company has received accounting guidance from the Mississippi PSC allowing the continued accrual of other future retirement costs for long-lived assets that the Company does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. | ||||||||||||||||||||||||
The Company has AROs related to various landfill sites, underground storage tanks, deep injection wells, water wells, substation removal, mine reclamation, and asbestos removal. The Company also has identified AROs related to certain transmission and distribution facilities, certain wireless communication towers, and certain structures authorized by the U.S. Army Corps of Engineers. However, liabilities for the removal of these assets have not been recorded because the settlement timing for the AROs related to these assets is indeterminable and, therefore, the fair value of the AROs cannot be reasonably estimated. A liability for these AROs will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The Company will continue to recognize in the statements of operations allowed removal costs in accordance with its regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability, as ordered by the Mississippi PSC, and are reflected in the balance sheets. | ||||||||||||||||||||||||
Details of the ARO included in the balance sheets are as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 41,910 | $ | 42,115 | ||||||||||||||||||||
Liabilities settled | (2,529 | ) | (24 | ) | ||||||||||||||||||||
Accretion | 1,969 | 1,840 | ||||||||||||||||||||||
Cash flow revisions | 6,898 | (2,021 | ) | |||||||||||||||||||||
Balance at end of year | $ | 48,248 | $ | 41,910 | ||||||||||||||||||||
The increase in cash flow revisions in 2014 related to the Company's AROs associated with Watson landfill and Greene County asbestos. | ||||||||||||||||||||||||
On December 19, 2014, the EPA issued the Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule), but has not yet published it in the Federal Register. The CCR Rule will regulate the disposal of CCR, including coal ash and gypsum, as non-hazardous solid waste in landfills and surface impoundments at active generating power plants. The ultimate impact of the CCR Rule cannot be determined at this time and will depend on the Company's ongoing review of the CCR Rule, the results of initial and ongoing minimum criteria assessments, and the outcome of legal challenges. The cost and timing of potential ash pond closure and ongoing monitoring activities that may be required in connection with the CCR Rule is also uncertain; however, the Company has developed a preliminary nominal dollar estimate of costs associated with closure and groundwater monitoring of ash ponds in place of approximately $64 million and ongoing post-closure care of approximately $12 million. The Company will record AROs for the estimated closure costs required under the CCR Rule during 2015. The Company's results of operations, cash flows, and financial condition could be significantly impacted if such costs are not recovered through regulated rates. | ||||||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | Allowance for Funds Used During Construction | |||||||||||||||||||||||
In accordance with regulatory treatment, the Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently from such allowance, AFUDC increases the revenue requirement and is recovered over the service life of the plant through a higher rate base and higher depreciation. The equity component of AFUDC is not included in the calculation of taxable income. The average annual AFUDC rate was 6.91%, 6.89%, and 7.04% for the years ended December 31, 2014, 2013, and 2012, respectively. AFUDC equity was $136.4 million, $121.6 million, and $64.8 million in 2014, 2013, and 2012, respectively. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles | |||||||||||||||||||||||
The Company evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance or an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. | ||||||||||||||||||||||||
Reserves, Damages, and Recoveries | Provision for Property Damage | |||||||||||||||||||||||
The Company carries insurance for the cost of certain types of damage to generation plants and general property. However, the Company is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, the Company accrues for the cost of such damage through an annual expense accrual credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every three years the Mississippi PSC, MPUS, and the Company will agree on SRR revenue level(s) for the ensuing period, based on historical data, expected exposure, type and amount of insurance coverage, excluding insurance cost, and any other relevant information. The accrual amount and the reserve balance are determined based on the SRR revenue level(s). If a significant change in circumstances occurs, then the SRR revenue level can be adjusted more frequently if the Company and the MPUS or the Mississippi PSC deem the change appropriate. The property damage reserve accrual will be the difference between the approved SRR revenues and the SRR revenue requirement, excluding any accrual to the reserve. In addition, SRR allows the Company to set up a regulatory asset, pending review, if the allowable actual retail property damage costs exceed the amount in the retail property damage reserve. In 2014, 2013, and 2012, the Company made retail accruals of $3.3 million, $3.2 million, and $3.5 million, respectively. The Company accrued $0.3 million annually in 2014, 2013, and 2012 for the wholesale jurisdiction. As of December 31, 2014, the property damage reserve balances were $60.7 million and $1.0 million for retail and wholesale, respectively. | ||||||||||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | Materials and Supplies | |||||||||||||||||||||||
Generally, materials and supplies include the average cost of transmission, distribution, mining, and generating plant materials. Materials are charged to inventory when purchased and then expensed, capitalized to plant, or charged to fuel stock, as appropriate, at weighted-average cost when utilized. | ||||||||||||||||||||||||
Fuel Inventory | Fuel Inventory | |||||||||||||||||||||||
Fuel inventory includes the average cost of coal, lignite, natural gas, oil, transportation and emissions allowances. Fuel is charged to inventory when purchased, except for the cost of owning and operating the lignite mine related to the Kemper IGCC which is charged to inventory as incurred, and then expensed, at weighted average cost, as used and recovered by the Company through fuel cost recovery rates or capitalized as part of the Kemper IGCC costs if used for testing. The retail rate is approved by the Mississippi PSC and the wholesale rates are approved by the FERC. Emissions allowances granted by the EPA are included in inventory at zero cost. | ||||||||||||||||||||||||
Financial Instruments | Financial Instruments | |||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 9 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from the fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Fuel and interest rate derivative contracts qualify as cash flow hedges of anticipated transactions or are recoverable through the Mississippi PSC approved fuel-hedging program as discussed below result in the deferral of related gains and losses in OCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Foreign currency exchange rate hedges are designated as fair value hedges. Settled foreign currency exchange hedges are recorded in CWIP. Any ineffectiveness arising from these would be recognized currently in net income; however, the Company has regulatory approval allowing it to defer any ineffectiveness arising from hedging instruments relating to the Kemper IGCC to a regulatory asset. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of operations. The amounts related to derivatives on the cash flow statement are classified in the same category as the items being hedged. See Note 10 for additional information regarding derivatives. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company has no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company has an ECM clause which, among other things, allows the Company to utilize financial instruments to hedge its fuel commitments. Changes in the fair value of these financial instruments are recorded as regulatory assets or liabilities. Amounts paid or received as a result of financial settlement of these instruments are classified as fuel expense and are included in the ECM factor applied to customer billings. The Company's jurisdictional wholesale customers have a similar ECM mechanism, which has been approved by the FERC. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | Comprehensive Income | |||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income. | ||||||||||||||||||||||||
Variable Interest Entities | Variable Interest Entities | |||||||||||||||||||||||
The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. | ||||||||||||||||||||||||
The Company is required to provide financing for all costs associated with the mine development and operation under a contract with Liberty Fuels Company, LLC, a subsidiary of North American Coal Corporation (Liberty Fuels), in conjunction with the construction of the Kemper IGCC. Liberty Fuels qualifies as a VIE for which the Company is the primary beneficiary. For the year ended December 31, 2014, the VIE consolidation resulted in an ARO asset and associated liability in the amounts of $21.0 million and $23.6 million, respectively. For the year ended December 31, 2013, the VIE consolidation resulted in an ARO and an associated liability in the amounts of $21.0 million and $22.7 million, respectively. For the year ended December 31, 2012, the VIE consolidation resulted in an ARO and associated liability in the amounts of $21.0 million and $21.8 million, respectively. See Note 3 under "Integrated Coal Gasification Combined Cycle" for additional information. | ||||||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
General | General | |||||||||||||||||||||||
Southern Power Company is a wholly-owned subsidiary of The Southern Company (Southern Company), which is also the parent company of four traditional operating companies, SCS, SouthernLINC Wireless, Southern Company Holdings, Inc. (Southern Holdings), Southern Nuclear, and other direct and indirect subsidiaries. The traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power Company and its subsidiaries (the Company) construct, acquire, own, and manage generation assets, including renewable energy projects, and sell electricity at market-based rates in the wholesale market. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. SouthernLINC Wireless provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber cable services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, primarily for Southern Company's investments in leveraged leases. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants. | ||||||||||||||||||||||||
Southern Power Company and certain of its generation subsidiaries are subject to regulation by the FERC. The Company follows GAAP. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. This includes an adjustment to the presentation of prepaid long-term service agreements (LTSA) to present amounts as noncurrent assets on the consolidated balance sheets. Prior period amounts recorded within other current assets have been reclassified to conform to the current presentation. See "Long-Term Service Agreements" herein for additional information. | ||||||||||||||||||||||||
The financial statements include the accounts of Southern Power Company and its wholly-owned subsidiaries, Southern Company – Florida, LLC, Oleander Power Project, LP, and Nacogdoches Power, LLC, which own, operate, and maintain the Company's ownership interests in Plants Stanton Unit A, Oleander, and Nacogdoches, respectively. The financial statements also include the accounts of Southern Power Company's wholly-owned subsidiaries, SRE and SRP. SRE and SRP were formed to construct, acquire, own, and manage renewable generation assets and sell electricity at market-based prices in the wholesale market. Through STR, a jointly-owned subsidiary owned 90% by SRE and 10% by TRE, SRE and its subsidiaries own, operate, and maintain Plants Adobe, Apex, Campo Verde, Cimarron, Granville, Macho Springs, and Spectrum. Through SG2 Holdings, a jointly-owned subsidiary owned 51% by SRP and 49% by First Solar, SRP owns, operates, and maintains Plant Imperial Valley. All intercompany accounts and transactions have been eliminated in consolidation. | ||||||||||||||||||||||||
Recently Issued Accounting Standards | Recently Issued Accounting Standards | |||||||||||||||||||||||
On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The Company continues to evaluate the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined. | ||||||||||||||||||||||||
Affiliate Transactions | Affiliate Transactions | |||||||||||||||||||||||
Southern Power Company has an agreement with SCS under which the following services are rendered to the Company at amounts in compliance with FERC regulation: general and design engineering, purchasing, accounting, finance and treasury, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, labor, and other services with respect to business and operations, construction management, and transactions associated with the Southern Company system's fleet of generating units. Because the Company has no employees, all employee-related charges are rendered at amounts in compliance with FERC regulation under agreements with SCS. Costs for all of these services from SCS amounted to approximately $125.9 million in 2014, $117.6 million in 2013, and $125.4 million in 2012. Of these costs, approximately $124.8 million in 2014, $114.3 million in 2013, and $107.7 million in 2012 were other operations and maintenance expenses; the remainder was recorded to plant in service. Cost allocation methodologies used by SCS prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies. | ||||||||||||||||||||||||
The Company has several agreements with SCS for transmission services. Transmission purchased from affiliates totaled $6.8 million in 2014, $8.3 million in 2013, and $6.6 million in 2012. All charges were billed to the Company based on the Southern Company Open Access Transmission Tariff as filed with the FERC. | ||||||||||||||||||||||||
Total billings for all PPAs with affiliates were $156.4 million, $148.4 million, and $159.9 million in 2014, 2013, and 2012, respectively. Deferred amounts outstanding as of December 31 are included in the balance sheet as follows: | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Other deferred charges and assets - affiliated | $ | 2.9 | $ | 1.9 | ||||||||||||||||||||
Other current liabilities | — | (4.2 | ) | |||||||||||||||||||||
Deferred capacity revenues - affiliated | (15.3 | ) | (15.3 | ) | ||||||||||||||||||||
Total deferred amounts outstanding | $ | (12.4 | ) | $ | (17.6 | ) | ||||||||||||||||||
Revenue recognized under affiliate PPAs accounted for as operating leases totaled $74.8 million, $69.0 million, and $76.2 million in 2014, 2013, and 2012, respectively. The Company and the traditional operating companies may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See "Revenues" herein for additional information. | ||||||||||||||||||||||||
The Company and the traditional operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. | ||||||||||||||||||||||||
Revenues | Revenues | |||||||||||||||||||||||
The Company sells capacity at rates specified under contractual terms for long-term PPAs. These PPAs are generally accounted for as operating leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Capacity revenues from PPAs classified as non-derivatives or normal sales are recognized at the lesser of the levelized amount or the amount billable under the contract over the respective contract periods. When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements. | ||||||||||||||||||||||||
The Company may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains (losses) on such contracts are recorded in wholesale revenues. See Note 9 for further information. | ||||||||||||||||||||||||
Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. All revenues under solar PPAs are accounted for as contingent revenues and recognized as services are performed. Transmission revenues and other fees are recognized as earned as other operating revenues. Revenues are recorded on a gross basis for all full requirements PPAs. See "Financial Instruments" herein for additional information. | ||||||||||||||||||||||||
Significant portions of the Company's revenues have been derived from certain customers pursuant to PPAs. The following table shows the percentage of total revenues for the top three customers: | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
FPL | 10.1 | % | 11.8 | % | 12.8 | % | ||||||||||||||||||
Georgia Power | 9.7 | % | 10.7 | % | 12.5 | % | ||||||||||||||||||
Duke Energy Corporation | 9.1 | % | 10.3 | % | 5.9 | % | ||||||||||||||||||
Fuel Costs | Fuel Costs | |||||||||||||||||||||||
Fuel costs are expensed as the fuel is used. Fuel costs also include emissions allowances which are expensed as the emissions occur. | ||||||||||||||||||||||||
Income and Other Taxes | Income and Other Taxes | |||||||||||||||||||||||
The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. | ||||||||||||||||||||||||
Under the American Recovery and Reinvestment Act of 2009 (ARRA), and the American Taxpayer Relief Act of 2012 (ATRA), certain projects are eligible for federal ITCs. The credits are recorded as a deferred credit and are amortized to income tax expense over the life of the asset. Credits amortized in this manner amounted to $11.4 million, $5.5 million, and $2.6 million in 2014, 2013, and 2012, respectively. Furthermore, the tax basis of the asset is reduced by 50% of the credits received, resulting in a net deferred tax asset. The Company has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. Federal and state ITCs available to reduce income taxes payable were not fully utilized during the year and will be carried forward and utilized in future years. See Note 5 under "Effective Tax Rate" for additional information. | ||||||||||||||||||||||||
In accordance with accounting standards related to the uncertainty in income taxes, the Company recognizes tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 5 under "Unrecognized Tax Benefits" for additional information. | ||||||||||||||||||||||||
Property, Plant, and Equipment | Property, Plant, and Equipment | |||||||||||||||||||||||
The Company's depreciable property, plant, and equipment consists entirely of generation assets. | ||||||||||||||||||||||||
Property, plant, and equipment is stated at original cost. Original cost includes: materials, direct labor incurred by contractors and affiliated companies, minor items of property, and interest capitalized. Interest is capitalized on qualifying projects during the development and construction period. The cost to replace significant items of property defined as retirement units is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred. | ||||||||||||||||||||||||
Acquisitions | Acquisition Accounting | |||||||||||||||||||||||
The Company acquires generation assets as part of its overall growth strategy. The Company accounts for business acquisitions from non-affiliates as business combinations. Accordingly, the Company includes these operations in the consolidated financial statements from the respective date of acquisition. The purchase price, including contingent consideration, if any, of each acquisition is allocated based on the fair value of the identifiable assets and liabilities. Assets acquired that do not meet the definition of a business in accordance with GAAP are accounted for as asset acquisitions. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Any due diligence or transition costs incurred by the Company for successful or potential acquisitions are expensed as incurred. | ||||||||||||||||||||||||
Depreciation, Depletion and Amortization | Depreciation | |||||||||||||||||||||||
Beginning in 2014, the Company changed to component depreciation, where the depreciation of the original cost of assets is computed principally by the straight-line method over the estimated useful lives of assets as determined by management. Certain generation assets are now depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of and revenues from these assets. The primary assets in property, plant, and equipment are power plants, which have estimated useful lives ranging from 35 to 45 years. The Company reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on net income in the near term. The book value of plant-in-service as of December 31, 2014 that is depreciated on a units-of-production basis was approximately $470.2 million. | ||||||||||||||||||||||||
When property subject to depreciation is retired or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed from the accounts and a gain or loss is recognized. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. | ||||||||||||||||||||||||
Prior to 2014, the Company computed depreciation of the original cost of assets under the straight-line method and applied a composite depreciation rate based on the assets' estimated useful lives as determined by management. | ||||||||||||||||||||||||
Long-Term Service Agreements | Long-Term Service Agreements | |||||||||||||||||||||||
The Company has entered into LTSAs for the purpose of securing maintenance support for substantially all of its generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. | ||||||||||||||||||||||||
Payments made under the LTSAs prior to the performance of any planned inspections or unplanned capital maintenance are recorded as a prepayment in noncurrent assets on the balance sheets and are recorded as payments pursuant to LTSAs in the statements of cash flows. All work performed is capitalized or charged to expense as appropriate based on the nature of the work when performed; therefore, these charges are non-cash and are not reflected in the statements of cash flows. | ||||||||||||||||||||||||
Impairment of Long-Lived Assets and Intangibles | Impairment of Long-Lived Assets and Intangibles | |||||||||||||||||||||||
The Company evaluates long-lived assets and finite-lived intangibles for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company's intangible assets consist of acquired PPAs that are amortized over the term of the PPA and goodwill resulting from acquisitions. The average term of these PPAs is 20 years. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. | ||||||||||||||||||||||||
Emission Reduction Credits | Emission Reduction Credits | |||||||||||||||||||||||
The Company has acquired emission reduction credits necessary for future unspecified construction in areas designated by the EPA as non-attainment areas for nitrogen oxide or volatile organic compound emissions. These credits are reflected on the balance sheets at historical cost. The cost of emission reduction offsets to be surrendered are generally transferred to CWIP upon commencement of construction. The total emission reduction credits were $11.0 million at December 31, 2014 and 2013. | ||||||||||||||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||||||||||||||
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less. | ||||||||||||||||||||||||
Materials and Supplies | Materials and Supplies | |||||||||||||||||||||||
Generally, materials and supplies include the average cost of generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. | ||||||||||||||||||||||||
Fuel Inventory | Fuel Inventory | |||||||||||||||||||||||
Fuel inventory includes the cost of oil, natural gas, biomass, and emissions allowances. The Company maintains oil inventory for use at several generating units. The Company has contracts in place for natural gas storage to support normal operations of the Company's natural gas generating units. The Company maintains biomass inventory for use at Plant Nacogdoches. Inventory is maintained using the weighted average cost method. Fuel inventory and emissions allowances are recorded at actual cost when purchased and then expensed at weighted average cost as used. Emissions allowances granted by the EPA are included at zero cost. | ||||||||||||||||||||||||
Financial Instruments | Financial Instruments | |||||||||||||||||||||||
The Company uses derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, and electricity purchases and sales. All derivative financial instruments are recognized as either assets or liabilities (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 8 for additional information regarding fair value. Substantially all of the Company's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions result in the deferral of related gains and losses in AOCI until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded in the financial statement line item where they will eventually settle. See Note 9 for additional information regarding derivatives. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. | ||||||||||||||||||||||||
The Company does not offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. Additionally, the Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2014. | ||||||||||||||||||||||||
The Company is exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Company has established controls to determine and monitor the creditworthiness of counterparties in order to mitigate the Company's exposure to counterparty credit risk. | ||||||||||||||||||||||||
Comprehensive Income | Comprehensive Income | |||||||||||||||||||||||
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, and reclassifications of amounts included in net income. | ||||||||||||||||||||||||
Variable Interest Entities | Variable Interest Entities | |||||||||||||||||||||||
The primary beneficiary of a variable interest entity (VIE) is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. | ||||||||||||||||||||||||
The Company has certain wholly-owned subsidiaries that are determined to be VIEs. The Company is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | |||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Retiree benefit plans | $ | 3,469 | $ | 1,760 | (a,p) | |||||||||||||||||||
Deferred income tax charges | 1,458 | 1,376 | (b) | |||||||||||||||||||||
Loss on reacquired debt | 267 | 293 | (c) | |||||||||||||||||||||
Fuel-hedging-asset | 202 | 58 | (d,p) | |||||||||||||||||||||
Deferred PPA charges | 185 | 180 | (e,p) | |||||||||||||||||||||
Vacation pay | 177 | 171 | (f,p) | |||||||||||||||||||||
Under recovered regulatory clause revenues | 157 | 70 | (g) | |||||||||||||||||||||
Kemper IGCC regulatory assets | 148 | 76 | (h) | |||||||||||||||||||||
Asset retirement obligations-asset | 119 | 145 | (b,p) | |||||||||||||||||||||
Nuclear outage | 99 | 78 | (g) | |||||||||||||||||||||
Property damage reserves-asset | 98 | 37 | (i) | |||||||||||||||||||||
Cancelled construction projects | 67 | 70 | (j) | |||||||||||||||||||||
Environmental remediation-asset | 64 | 62 | (k,p) | |||||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 57 | 65 | (l) | |||||||||||||||||||||
Other regulatory assets | 195 | 222 | (m) | |||||||||||||||||||||
Other cost of removal obligations | (1,229 | ) | (1,289 | ) | (b) | |||||||||||||||||||
Kemper regulatory liability (Mirror CWIP) | (271 | ) | (91 | ) | (h) | |||||||||||||||||||
Deferred income tax credits | (192 | ) | (203 | ) | (b) | |||||||||||||||||||
Property damage reserves-liability | (181 | ) | (191 | ) | (n) | |||||||||||||||||||
Asset retirement obligations-liability | (130 | ) | (139 | ) | (b,p) | |||||||||||||||||||
Other regulatory liabilities | (95 | ) | (126 | ) | (o) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 4,664 | $ | 2,624 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the two-year period from January 2015 through December 2016 in accordance with Georgia Power's 2013 ARP. See Note 3 under "Retail Regulatory Matters – Georgia Power – Rate Plans" for additional information. At December 31, 2014, other cost of removal obligations included $8.4 million recorded as authorized by the Florida PSC in the Settlement Agreement approved in December 2013 (Gulf Power Settlement Agreement). | |||||||||||||||||||||||
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. | |||||||||||||||||||||||
(d) | Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||||||||||||||||||
(e) | Recovered over the life of the PPA for periods up to nine years. | |||||||||||||||||||||||
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(g) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years. | |||||||||||||||||||||||
(h) | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||||||||||||||
(i) | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding eight years. | |||||||||||||||||||||||
(j) | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||||||||||||||||||
(k) | Recovered through the environmental cost recovery clause when the remediation is performed. | |||||||||||||||||||||||
(l) | Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years. | |||||||||||||||||||||||
(m) | Comprised of numerous immaterial components including property taxes, generation site selection/evaluation costs, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding 10 years or, as applicable, over the remaining life of the asset but not beyond 2031. | |||||||||||||||||||||||
(n) | Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. | |||||||||||||||||||||||
(o) | Comprised of numerous immaterial components including over-recovered regulatory clause revenues, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, nuclear disposal fees, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years. | |||||||||||||||||||||||
(p) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
Property Plant and Equipment | The Southern Company system's property, plant, and equipment in service consisted of the following at December 31: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 37,892 | $ | 35,360 | ||||||||||||||||||||
Transmission | 9,884 | 9,289 | ||||||||||||||||||||||
Distribution | 17,123 | 16,499 | ||||||||||||||||||||||
General | 4,198 | 3,958 | ||||||||||||||||||||||
Plant acquisition adjustment | 123 | 123 | ||||||||||||||||||||||
Utility plant in service | 69,220 | 65,229 | ||||||||||||||||||||||
Information technology equipment and software | 244 | 242 | ||||||||||||||||||||||
Communications equipment | 439 | 437 | ||||||||||||||||||||||
Other | 110 | 113 | ||||||||||||||||||||||
Other plant in service | 793 | 792 | ||||||||||||||||||||||
Total plant in service | $ | 70,013 | $ | 66,021 | ||||||||||||||||||||
Assets Acquired Under Capital Leases | Assets acquired under a capital lease are included in property, plant, and equipment and are further detailed in the table below: | |||||||||||||||||||||||
Asset Balances at | ||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Office building | $ | 61 | $ | 61 | ||||||||||||||||||||
Nitrogen plant | 83 | 83 | ||||||||||||||||||||||
Computer-related equipment | 60 | 62 | ||||||||||||||||||||||
Gas pipeline | 6 | 6 | ||||||||||||||||||||||
Less: Accumulated amortization | (49 | ) | (48 | ) | ||||||||||||||||||||
Balance, net of amortization | $ | 161 | $ | 164 | ||||||||||||||||||||
Acquisitions | Acquisitions entered into or made by Southern Power during 2014 and 2013 are detailed in the table below: | |||||||||||||||||||||||
MW Capacity | Percentage | Year | Party Under PPA Contract | PPA Contract Period | Purchase Price | |||||||||||||||||||
Ownership | of | for Plant Output | ||||||||||||||||||||||
Operation | ||||||||||||||||||||||||
(millions) | ||||||||||||||||||||||||
SG2 Imperial Valley, LLC (a) | 150 | 51% | 2014 | San Diego Gas & | 25 years | $504.70 | (c) | |||||||||||||||||
Electric Company | ||||||||||||||||||||||||
Macho Springs Solar LLC (b) | 50 | 90 | 2014 | El Paso Electric Company | 20 years | $130.00 | (d) | |||||||||||||||||
Adobe Solar, LLC (b) | 20 | 90 | 2014 | Southern California | 20 years | $96.20 | (d) | |||||||||||||||||
Edison Company | ||||||||||||||||||||||||
Campo Verde Solar, LLC (b)(e) | 139 | 90 | 2013 | San Diego Gas & | 20 years | $136.60 | (d) | |||||||||||||||||
Electric Company | ||||||||||||||||||||||||
(a) | This acquisition was made by Southern Power through its subsidiaries Southern Renewable Partnerships, LLC and SG2 Holdings, LLC. SG2 Holdings, LLC is jointly-owned by Southern Power and First Solar, Inc. | |||||||||||||||||||||||
(b) | This acquisition was made by Southern Power and Turner Renewable Energy, LLC through Southern Turner Renewable Energy, LLC. | |||||||||||||||||||||||
(c) | Reflects Southern Power's portion of the purchase price. | |||||||||||||||||||||||
(d) | Reflects 100% of the purchase price, including Turner Renewable Energy, LLC's 10% equity contribution. | |||||||||||||||||||||||
(e) | Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar, Inc. to complete the construction of the solar facility. | |||||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 2,018 | $ | 1,757 | ||||||||||||||||||||
Liabilities incurred | 18 | 6 | ||||||||||||||||||||||
Liabilities settled | (17 | ) | (16 | ) | ||||||||||||||||||||
Accretion | 102 | 97 | ||||||||||||||||||||||
Cash flow revisions | 80 | 174 | ||||||||||||||||||||||
Balance at end of year | $ | 2,201 | $ | 2,018 | ||||||||||||||||||||
Accumulated Provisions for Decommissioning | At December 31, 2014 and 2013, the accumulated provisions for decommissioning were as follows: | |||||||||||||||||||||||
External Trust Funds | Internal Reserves | Total | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Plant Farley | $ | 754 | $ | 713 | $ | 21 | $ | 21 | $ | 775 | $ | 734 | ||||||||||||
Plant Hatch | 496 | 469 | — | — | 496 | 469 | ||||||||||||||||||
Plant Vogtle Units 1 and 2 | 293 | 277 | — | — | 293 | 277 | ||||||||||||||||||
Estimated Cost of Decommissioning | The estimated costs of decommissioning as of December 31, 2014 based on the most current studies, which were performed in 2013 for Alabama Power's Plant Farley and in 2012 for the Georgia Power plants, were as follows for Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2: | |||||||||||||||||||||||
Plant Farley | Plant Hatch | Plant Vogtle | ||||||||||||||||||||||
Units 1 and 2 | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2037 | 2034 | 2047 | |||||||||||||||||||||
Completion year | 2076 | 2068 | 2072 | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 1,362 | $ | 549 | $ | 453 | ||||||||||||||||||
Spent fuel management | — | 131 | 115 | |||||||||||||||||||||
Non-radiated structures | 80 | 51 | 76 | |||||||||||||||||||||
Total site study costs | $ | 1,442 | $ | 731 | $ | 644 | ||||||||||||||||||
Net Investments in Leveraged Leases | Southern Company's net investment in domestic and international leveraged leases consists of the following at December 31: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Net rentals receivable | $ | 1,495 | $ | 1,440 | ||||||||||||||||||||
Unearned income | (752 | ) | (775 | ) | ||||||||||||||||||||
Investment in leveraged leases | 743 | 665 | ||||||||||||||||||||||
Deferred taxes from leveraged leases | (299 | ) | (287 | ) | ||||||||||||||||||||
Net investment in leveraged leases | $ | 444 | $ | 378 | ||||||||||||||||||||
Components of Income from Leveraged Leases | A summary of the components of income from the leveraged leases follows: | |||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Pretax leveraged lease income (loss) | $ | 24 | $ | (5 | ) | $ | 21 | |||||||||||||||||
Income tax expense | (9 | ) | 2 | (8 | ) | |||||||||||||||||||
Net leveraged lease income (loss) | $ | 15 | $ | (3 | ) | $ | 13 | |||||||||||||||||
Accumulated Other Comprehensive Income (Loss) Balances, Net of Tax Effects | Accumulated OCI (loss) balances, net of tax effects, were as follows: | |||||||||||||||||||||||
Qualifying | Marketable | Pension and Other | Accumulated Other | |||||||||||||||||||||
Hedges | Securities | Postretirement | Comprehensive | |||||||||||||||||||||
Benefit Plans | Income (Loss) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at December 31, 2013 | $ | (36 | ) | $ | — | $ | (39 | ) | $ | (75 | ) | |||||||||||||
Current period change | (5 | ) | — | (48 | ) | (53 | ) | |||||||||||||||||
Balance at December 31, 2014 | $ | (41 | ) | $ | — | $ | (87 | ) | $ | (128 | ) | |||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | |||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Deferred income tax charges | $ | 525 | $ | 519 | (a,k) | |||||||||||||||||||
Loss on reacquired debt | 80 | 86 | (b) | |||||||||||||||||||||
Vacation pay | 65 | 63 | (c,j) | |||||||||||||||||||||
Under/(over) recovered regulatory clause revenues | 57 | (18 | ) | (d) | ||||||||||||||||||||
Fuel-hedging losses | 53 | 8 | (e) | |||||||||||||||||||||
Other regulatory assets | 49 | 52 | (f) | |||||||||||||||||||||
Asset retirement obligations | (125 | ) | (132 | ) | (a) | |||||||||||||||||||
Other cost of removal obligations | (744 | ) | (828 | ) | (a) | |||||||||||||||||||
Deferred income tax credits | (72 | ) | (75 | ) | (a) | |||||||||||||||||||
Fuel-hedging gains | (1 | ) | (8 | ) | (e) | |||||||||||||||||||
Nuclear outage | 56 | 51 | (d) | |||||||||||||||||||||
Natural disaster reserve | (84 | ) | (96 | ) | (h) | |||||||||||||||||||
Other regulatory liabilities | (8 | ) | (11 | ) | (d,g) | |||||||||||||||||||
Retiree benefit plans | 882 | 461 | (i,j) | |||||||||||||||||||||
Regulatory deferrals | 13 | 20 | (l) | |||||||||||||||||||||
Nuclear fuel disposal fee | (8 | ) | — | (m) | ||||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 738 | $ | 92 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(b) | Recovered over the remaining life of the original issue, which may range up to 50 years. | |||||||||||||||||||||||
(c) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(d) | Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years. | |||||||||||||||||||||||
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||||||||||||||||||
(f) | Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. | |||||||||||||||||||||||
(g) | Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. | |||||||||||||||||||||||
(h) | Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. | |||||||||||||||||||||||
(i) | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | |||||||||||||||||||||||
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(k) | Included in the deferred income tax charges are $18 million for 2014 and $20 million for 2013 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. | |||||||||||||||||||||||
(l) | Recorded and amortized as approved by the Alabama PSC for a period of five years. | |||||||||||||||||||||||
(m) | Recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The term of deferral is conditional upon resolution by the DOE. See Note 3 for additional information. | |||||||||||||||||||||||
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 11,670 | $ | 11,314 | ||||||||||||||||||||
Transmission | 3,579 | 3,287 | ||||||||||||||||||||||
Distribution | 6,196 | 5,934 | ||||||||||||||||||||||
General | 1,623 | 1,545 | ||||||||||||||||||||||
Plant acquisition adjustment | 12 | 12 | ||||||||||||||||||||||
Total plant in service | $ | 23,080 | $ | 22,092 | ||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 730 | $ | 589 | ||||||||||||||||||||
Liabilities incurred | 1 | — | ||||||||||||||||||||||
Liabilities settled | (3 | ) | (1 | ) | ||||||||||||||||||||
Accretion | 45 | 40 | ||||||||||||||||||||||
Cash flow revisions | 56 | 102 | ||||||||||||||||||||||
Balance at end of year | $ | 829 | $ | 730 | ||||||||||||||||||||
Accumulated Provisions for Decommissioning | At December 31, the accumulated provisions for decommissioning were as follows: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
External trust funds | $ | 754 | $ | 713 | ||||||||||||||||||||
Internal reserves | 21 | 21 | ||||||||||||||||||||||
Total | $ | 775 | 734 | |||||||||||||||||||||
Estimated Cost of Decommissioning | The estimated costs of decommissioning as of December 31, 2014 based on the most current study performed in 2013 for Plant Farley are as follows: | |||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2037 | |||||||||||||||||||||||
Completion year | 2076 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 1,362 | ||||||||||||||||||||||
Non-radiated structures | 80 | |||||||||||||||||||||||
Total site study costs | $ | 1,442 | ||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | |||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Deferred income tax charges | $ | 53,234 | $ | 47,573 | (a) | |||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 3,024 | 3,351 | (b) | |||||||||||||||||||||
Asset retirement obligations | (5,087 | ) | (6,089 | ) | (a,j) | |||||||||||||||||||
Other cost of removal obligations | (242,997 | ) | (228,148 | ) | (a) | |||||||||||||||||||
Regulatory asset, offset to other cost of removal | 8,410 | — | (m) | |||||||||||||||||||||
Deferred income tax credits | (3,872 | ) | (5,238 | ) | (a) | |||||||||||||||||||
Loss on reacquired debt | 15,991 | 16,565 | (c) | |||||||||||||||||||||
Vacation pay | 10,006 | 9,521 | (d,j) | |||||||||||||||||||||
Under recovered regulatory clause revenues | 52,619 | 45,191 | (e) | |||||||||||||||||||||
Property damage reserve | (35,111 | ) | (35,380 | ) | (f) | |||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 73,474 | 17,043 | (g,j) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) gains | (112 | ) | (6,962 | ) | (g,j) | |||||||||||||||||||
PPA charges | 185,065 | 180,149 | (j,k) | |||||||||||||||||||||
Other regulatory assets | 9,753 | 12,772 | (l) | |||||||||||||||||||||
Environmental remediation | 48,271 | 50,384 | (h,j) | |||||||||||||||||||||
Other regulatory liabilities | (649 | ) | (8,804 | ) | (f,j) | |||||||||||||||||||
Retiree benefit plans, net | 147,625 | 68,296 | (i,j) | |||||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 319,644 | $ | 160,224 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(b) | Recovered and amortized over periods not exceeding 14 years. | |||||||||||||||||||||||
(c) | Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years. | |||||||||||||||||||||||
(d) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(e) | Recorded and recovered or amortized as approved by the Florida PSC, generally within one year. | |||||||||||||||||||||||
(f) | Recorded and recovered or amortized as approved by the Florida PSC. | |||||||||||||||||||||||
(g) | Fuel-hedging assets and liabilities are recognized over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the fuel cost recovery clause. | |||||||||||||||||||||||
(h) | Recovered through the environmental cost recovery clause when the remediation is performed. | |||||||||||||||||||||||
(i) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||||||||||||||||||
(j) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(k) | Recovered over the life of the PPA for periods up to nine years. | |||||||||||||||||||||||
(l) | Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating projects. | |||||||||||||||||||||||
(m) Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013. See Note 3 for additional information. | ||||||||||||||||||||||||
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Generation | $ | 2,637,817 | $ | 2,607,166 | ||||||||||||||||||||
Transmission | 515,754 | 473,378 | ||||||||||||||||||||||
Distribution | 1,156,872 | 1,117,024 | ||||||||||||||||||||||
General | 182,734 | 164,065 | ||||||||||||||||||||||
Plant acquisition adjustment | 1,776 | 2,031 | ||||||||||||||||||||||
Total plant in service | $ | 4,494,953 | $ | 4,363,664 | ||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 16,184 | $ | 16,055 | ||||||||||||||||||||
Liabilities incurred | — | 518 | ||||||||||||||||||||||
Liabilities settled | (32 | ) | (1,913 | ) | ||||||||||||||||||||
Accretion | 718 | 751 | ||||||||||||||||||||||
Cash flow revisions | (159 | ) | 773 | |||||||||||||||||||||
Balance at end of year | $ | 16,711 | $ | 16,184 | ||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | |||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Retiree benefit plans | $ | 1,325 | $ | 691 | (a, j) | |||||||||||||||||||
Deferred income tax charges | 668 | 684 | (b, j) | |||||||||||||||||||||
Deferred income tax charges — Medicare subsidy | 34 | 38 | (c) | |||||||||||||||||||||
Loss on reacquired debt | 163 | 181 | (d, j) | |||||||||||||||||||||
Asset retirement obligations | 108 | 137 | (b, j) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 29 | 22 | (e, j) | |||||||||||||||||||||
Vacation pay | 91 | 88 | (f, j) | |||||||||||||||||||||
Building lease | 31 | 37 | (g, j) | |||||||||||||||||||||
Cancelled construction projects | 67 | 70 | (h) | |||||||||||||||||||||
Remaining net book value of retired units | 25 | 28 | (i) | |||||||||||||||||||||
Storm damage reserves | 98 | 37 | (c) | |||||||||||||||||||||
Other regulatory assets | 63 | 49 | (c) | |||||||||||||||||||||
Other cost of removal obligations | (60 | ) | (58 | ) | (b) | |||||||||||||||||||
Deferred income tax credits | (106 | ) | (112 | ) | (b, j) | |||||||||||||||||||
Other regulatory liabilities | (7 | ) | (6 | ) | (e, j) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 2,529 | $ | 1,886 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the remaining two-year period of January 2015 through December 2016 in accordance with the Company's 2013 ARP. | |||||||||||||||||||||||
(c) | Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding eight years. | |||||||||||||||||||||||
(d) | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 38 years. | |||||||||||||||||||||||
(e) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism. | |||||||||||||||||||||||
(f) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(g) | See Note 6 under "Capital Leases." Recovered over the remaining life of the building through 2020. | |||||||||||||||||||||||
(h) | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||||||||||||||||||
(i) | Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2022. | |||||||||||||||||||||||
(j) | Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Generation | $ | 15,201 | $ | 14,872 | ||||||||||||||||||||
Transmission | 5,086 | 4,859 | ||||||||||||||||||||||
Distribution | 8,913 | 8,620 | ||||||||||||||||||||||
General | 1,855 | 1,753 | ||||||||||||||||||||||
Plant acquisition adjustment | 28 | 28 | ||||||||||||||||||||||
Total plant in service | $ | 31,083 | $ | 30,132 | ||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Details of the AROs included in the balance sheets are as follows: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 1,222 | $ | 1,105 | ||||||||||||||||||||
Liabilities incurred | 9 | 2 | ||||||||||||||||||||||
Liabilities settled | (12 | ) | (13 | ) | ||||||||||||||||||||
Accretion | 53 | 55 | ||||||||||||||||||||||
Cash flow revisions | (17 | ) | 73 | |||||||||||||||||||||
Balance at end of year | $ | 1,255 | $ | 1,222 | ||||||||||||||||||||
Accumulated Provisions for Decommissioning | The site study costs and external trust funds for decommissioning as of December 31, 2014 based on the Company's ownership interests were as follows: | |||||||||||||||||||||||
Plant Hatch | Plant Vogtle | |||||||||||||||||||||||
Units 1 and 2 | ||||||||||||||||||||||||
Decommissioning periods: | ||||||||||||||||||||||||
Beginning year | 2034 | 2047 | ||||||||||||||||||||||
Completion year | 2068 | 2072 | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Site study costs: | ||||||||||||||||||||||||
Radiated structures | $ | 549 | $ | 453 | ||||||||||||||||||||
Spent fuel management | 131 | 115 | ||||||||||||||||||||||
Non-radiated structures | 51 | 76 | ||||||||||||||||||||||
Total site study costs | $ | 731 | $ | 644 | ||||||||||||||||||||
External trust funds | $ | 496 | $ | 293 | ||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
Regulatory Assets and Liabilities | Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to: | |||||||||||||||||||||||
2014 | 2013 | Note | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Retiree benefit plans – regulatory assets | $ | 169,317 | $ | 82,799 | (a,g) | |||||||||||||||||||
Property damage | (61,648 | ) | (60,092 | ) | (i) | |||||||||||||||||||
Deferred income tax charges | 222,599 | 140,185 | (c) | |||||||||||||||||||||
Property tax | 27,680 | 31,206 | (d) | |||||||||||||||||||||
Vacation pay | 11,172 | 10,214 | (e,g) | |||||||||||||||||||||
Loss on reacquired debt | 8,542 | 9,178 | (k) | |||||||||||||||||||||
Plant Daniel Units 3 and 4 regulatory assets | 23,013 | 18,821 | (j) | |||||||||||||||||||||
Other regulatory assets | 16,270 | 5,415 | (b) | |||||||||||||||||||||
Fuel-hedging (realized and unrealized) losses | 46,631 | 10,340 | (f,g) | |||||||||||||||||||||
Asset retirement obligations | 10,845 | 8,918 | (c) | |||||||||||||||||||||
Deferred income tax credits | (9,370 | ) | (10,191 | ) | (c) | |||||||||||||||||||
Other cost of removal obligations | (165,999 | ) | (156,683 | ) | (c) | |||||||||||||||||||
Kemper IGCC regulatory assets | 147,689 | 75,873 | (h) | |||||||||||||||||||||
Mirror CWIP / Kemper regulatory deferral | (270,779 | ) | (90,524 | ) | (h) | |||||||||||||||||||
Other regulatory liabilities | (4,198 | ) | (8,855 | ) | (b) | |||||||||||||||||||
Total regulatory assets (liabilities), net | $ | 171,764 | $ | 66,604 | ||||||||||||||||||||
Note: The recovery and amortization periods for these regulatory assets and (liabilities) are as follows: | ||||||||||||||||||||||||
(a) | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||||||||||||||||||
(b) | Recorded and recovered (amortized) as approved by the Mississippi PSC. | |||||||||||||||||||||||
(c) | Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||||||||||||||||||
(d) | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. | |||||||||||||||||||||||
(e) | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||||||||||||||||||
(f) | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the ECM. | |||||||||||||||||||||||
(g) | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||||||||||||||||||
(h) | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||||||||||||||
(i) | For additional information, see Note 1 under "Provision for Property Damage." | |||||||||||||||||||||||
(j) | Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. | |||||||||||||||||||||||
(k) | Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years. | |||||||||||||||||||||||
Property Plant and Equipment | The Company's property, plant, and equipment in service consisted of the following at December 31: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Generation | $ | 2,293,511 | $ | 1,475,264 | ||||||||||||||||||||
Transmission | 664,618 | 633,903 | ||||||||||||||||||||||
Distribution | 853,835 | 828,470 | ||||||||||||||||||||||
General | 484,711 | 439,721 | ||||||||||||||||||||||
Plant acquisition adjustment | 81,412 | 81,412 | ||||||||||||||||||||||
Total plant in service | $ | 4,378,087 | $ | 3,458,770 | ||||||||||||||||||||
Asset Retirement Obligations and Other Costs of Removal | Details of the ARO included in the balance sheets are as follows: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Balance at beginning of year | $ | 41,910 | $ | 42,115 | ||||||||||||||||||||
Liabilities settled | (2,529 | ) | (24 | ) | ||||||||||||||||||||
Accretion | 1,969 | 1,840 | ||||||||||||||||||||||
Cash flow revisions | 6,898 | (2,021 | ) | |||||||||||||||||||||
Balance at end of year | $ | 48,248 | $ | 41,910 | ||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | ||||||||||||||||||||||||
Schedule of Related Party Transactions | Deferred amounts outstanding as of December 31 are included in the balance sheet as follows: | |||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Other deferred charges and assets - affiliated | $ | 2.9 | $ | 1.9 | ||||||||||||||||||||
Other current liabilities | — | (4.2 | ) | |||||||||||||||||||||
Deferred capacity revenues - affiliated | (15.3 | ) | (15.3 | ) | ||||||||||||||||||||
Total deferred amounts outstanding | $ | (12.4 | ) | $ | (17.6 | ) | ||||||||||||||||||
Future Amortization Expense for PPAs | The amortization expense for the acquired PPAs for the years ended December 31, 2014, 2013, and 2012 was $2.5 million, $2.5 million, and $1.7 million, respectively, and the amortization for future periods is as follows: | |||||||||||||||||||||||
Amortization | ||||||||||||||||||||||||
Expense | ||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
2015 | $ | 2.5 | ||||||||||||||||||||||
2016 | 2.4 | |||||||||||||||||||||||
2017 | 2.5 | |||||||||||||||||||||||
2018 | 2.5 | |||||||||||||||||||||||
2019 | 2.5 | |||||||||||||||||||||||
2020 and beyond | 28.5 | |||||||||||||||||||||||
Total | $ | 40.9 | ||||||||||||||||||||||
Schedule of Revenue by Major Customers by Reporting Segments | The following table shows the percentage of total revenues for the top three customers: | |||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
FPL | 10.1 | % | 11.8 | % | 12.8 | % | ||||||||||||||||||
Georgia Power | 9.7 | % | 10.7 | % | 12.5 | % | ||||||||||||||||||
Duke Energy Corporation | 9.1 | % | 10.3 | % | 5.9 | % |
Retirement_Benefits_Tables
Retirement Benefits (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | Actuarial Assumptions | |||||||||||||||
The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%. | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.17 | % | 5.02 | % | 4.26 | % | ||||||||||
Other postretirement benefit plans | 4.04 | 4.85 | 4.05 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 7.15 | 7.13 | 7.29 | |||||||||||||
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | |||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
Effect of 1% annual increase or decrease in assumed medical care cost on APBO and service and interest cost components | An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | |||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in millions) | ||||||||||||||||
Benefit obligation | $ | 140 | $ | (117 | ) | |||||||||||
Service and interest costs | 6 | (5 | ) | |||||||||||||
Changes in projected benefit obligations and fair value of plan assets | Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 8,863 | $ | 9,302 | ||||||||||||
Service cost | 213 | 232 | ||||||||||||||
Interest cost | 435 | 389 | ||||||||||||||
Benefits paid | (382 | ) | (357 | ) | ||||||||||||
Actuarial (gain) loss | 1,780 | (703 | ) | |||||||||||||
Balance at end of year | 10,909 | 8,863 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 8,733 | 7,953 | ||||||||||||||
Actual return on plan assets | 797 | 1,098 | ||||||||||||||
Employer contributions | 542 | 39 | ||||||||||||||
Benefits paid | (382 | ) | (357 | ) | ||||||||||||
Fair value of plan assets at end of year | 9,690 | 8,733 | ||||||||||||||
Accrued liability | $ | (1,219 | ) | $ | (130 | ) | ||||||||||
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization | Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
Prior | Net (Gain) Loss | |||||||||||||||
Service | ||||||||||||||||
Cost | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2014: | ||||||||||||||||
Accumulated OCI | $ | 4 | $ | 130 | ||||||||||||
Regulatory assets | 51 | 3,022 | ||||||||||||||
Total | $ | 55 | $ | 3,152 | ||||||||||||
Balance at December 31, 2013: | ||||||||||||||||
Accumulated OCI | $ | 5 | $ | 59 | ||||||||||||
Regulatory assets | 75 | 1,575 | ||||||||||||||
Total | $ | 80 | $ | 1,634 | ||||||||||||
Estimated amortization in net periodic pension cost in 2015: | ||||||||||||||||
Accumulated OCI | $ | 1 | $ | 9 | ||||||||||||
Regulatory assets | 24 | 206 | ||||||||||||||
Total | $ | 25 | $ | 215 | ||||||||||||
Components of other comprehensive income along with changes in balances of regulatory assets and regulatory liabilities related to defined benefit pension plans | The components of OCI and the changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
Accumulated | Regulatory Assets | |||||||||||||||
OCI | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2012 | $ | 125 | $ | 3,013 | ||||||||||||
Net gain | (52 | ) | (1,145 | ) | ||||||||||||
Change in prior service costs | — | 1 | ||||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1 | ) | (26 | ) | ||||||||||||
Amortization of net gain (loss) | (8 | ) | (192 | ) | ||||||||||||
Total reclassification adjustments | (9 | ) | (218 | ) | ||||||||||||
Total change | (61 | ) | (1,362 | ) | ||||||||||||
Balance at December 31, 2013 | $ | 64 | $ | 1,651 | ||||||||||||
Net gain | 75 | 1,552 | ||||||||||||||
Change in prior service costs | — | 1 | ||||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1 | ) | (25 | ) | ||||||||||||
Amortization of net gain (loss) | (4 | ) | (106 | ) | ||||||||||||
Total reclassification adjustments | (5 | ) | (131 | ) | ||||||||||||
Total change | 70 | 1,422 | ||||||||||||||
Balance at December 31, 2014 | $ | 134 | $ | 3,073 | ||||||||||||
Estimated pension benefit payments | At December 31, 2014, estimated benefit payments were as follows: | |||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 522 | ||||||||||||||
2016 | 450 | |||||||||||||||
2017 | 478 | |||||||||||||||
2018 | 499 | |||||||||||||||
2019 | 524 | |||||||||||||||
2020 to 2024 | 2,962 | |||||||||||||||
Changes in the accumulated postretirement benefit obligations (APBO) and in fair value of plan assets | Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 1,682 | $ | 1,872 | ||||||||||||
Service cost | 21 | 24 | ||||||||||||||
Interest cost | 79 | 74 | ||||||||||||||
Benefits paid | (102 | ) | (94 | ) | ||||||||||||
Actuarial (gain) loss | 300 | (200 | ) | |||||||||||||
Plan amendments | (2 | ) | — | |||||||||||||
Retiree drug subsidy | 8 | 6 | ||||||||||||||
Balance at end of year | 1,986 | 1,682 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 901 | 821 | ||||||||||||||
Actual return on plan assets | 54 | 129 | ||||||||||||||
Employer contributions | 39 | 39 | ||||||||||||||
Benefits paid | (94 | ) | (88 | ) | ||||||||||||
Fair value of plan assets at end of year | 900 | 901 | ||||||||||||||
Accrued liability | $ | (1,086 | ) | $ | (781 | ) | ||||||||||
Amounts included in accumulated other comprehensive income and regulatory assets related to other postretirement benefit plans | Presented below are the amounts included in accumulated OCI and net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
Prior | Net (Gain) | |||||||||||||||
Service | Loss | |||||||||||||||
Cost | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2014: | ||||||||||||||||
Accumulated OCI | $ | — | $ | 8 | ||||||||||||
Net regulatory assets (liabilities) | 2 | 364 | ||||||||||||||
Total | $ | 2 | $ | 372 | ||||||||||||
Balance at December 31, 2013: | ||||||||||||||||
Accumulated OCI | $ | — | $ | 1 | ||||||||||||
Net regulatory assets (liabilities) | 9 | 64 | ||||||||||||||
Total | $ | 9 | $ | 65 | ||||||||||||
Estimated amortization as net periodic postretirement benefit cost in 2015: | ||||||||||||||||
Accumulated OCI | $ | — | $ | — | ||||||||||||
Net regulatory assets (liabilities) | 4 | 17 | ||||||||||||||
Total | $ | 4 | $ | 17 | ||||||||||||
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The components of OCI, along with the changes in the balance of net regulatory assets (liabilities), related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
Accumulated | Net Regulatory | |||||||||||||||
OCI | Assets | |||||||||||||||
(Liabilities) | ||||||||||||||||
(in millions) | ||||||||||||||||
Balance at December 31, 2012 | $ | 7 | $ | 360 | ||||||||||||
Net loss | (6 | ) | (266 | ) | ||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of transition obligation | — | (5 | ) | |||||||||||||
Amortization of prior service costs | — | (4 | ) | |||||||||||||
Amortization of net gain (loss) | — | (12 | ) | |||||||||||||
Total reclassification adjustments | — | (21 | ) | |||||||||||||
Total change | (6 | ) | (287 | ) | ||||||||||||
Balance at December 31, 2013 | $ | 1 | $ | 73 | ||||||||||||
Net gain | 7 | 301 | ||||||||||||||
Change in prior service costs | — | (2 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | — | (4 | ) | |||||||||||||
Amortization of net gain (loss) | — | (2 | ) | |||||||||||||
Total reclassification adjustments | — | (6 | ) | |||||||||||||
Total change | 7 | 293 | ||||||||||||||
Balance at December 31, 2014 | $ | 8 | $ | 366 | ||||||||||||
Summary of estimation of future benefit payments and subsidy receipts based on assumptions used to measure accumulated benefit obligation for postretirement plans | Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | |||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 118 | $ | (10 | ) | $ | 108 | |||||||||
2016 | 124 | (11 | ) | 113 | ||||||||||||
2017 | 129 | (12 | ) | 117 | ||||||||||||
2018 | 132 | (13 | ) | 119 | ||||||||||||
2019 | 134 | (15 | ) | 119 | ||||||||||||
2020 to 2024 | 670 | (79 | ) | 591 | ||||||||||||
Composition of benefit plan assets along with targeted mix of assets | The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | |||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 42 | % | 41 | % | 40 | % | ||||||||||
International equity | 21 | 23 | 25 | |||||||||||||
Domestic fixed income | 24 | 26 | 24 | |||||||||||||
Global fixed income | 4 | 3 | 4 | |||||||||||||
Special situations | 1 | — | — | |||||||||||||
Real estate investments | 5 | 5 | 5 | |||||||||||||
Private equity | 3 | 2 | 2 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Pension Plans [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 419 | ||||||||||||
Other regulatory assets, deferred | 3,073 | 1,651 | ||||||||||||||
Other current liabilities | (42 | ) | (40 | ) | ||||||||||||
Employee benefit obligations | (1,177 | ) | (509 | ) | ||||||||||||
Accumulated OCI | 134 | 64 | ||||||||||||||
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 213 | $ | 232 | $ | 198 | ||||||||||
Interest cost | 435 | 389 | 393 | |||||||||||||
Expected return on plan assets | (645 | ) | (603 | ) | (581 | ) | ||||||||||
Recognized net loss | 110 | 200 | 95 | |||||||||||||
Net amortization | 26 | 27 | 30 | |||||||||||||
Net periodic pension cost | $ | 139 | $ | 245 | $ | 135 | ||||||||||
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 1,704 | $ | 704 | $ | — | $ | 2,408 | ||||||||
International equity* | 1,070 | 986 | — | 2,056 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 699 | — | 699 | ||||||||||||
Mortgage- and asset-backed securities | — | 188 | — | 188 | ||||||||||||
Corporate bonds | — | 1,135 | — | 1,135 | ||||||||||||
Pooled funds | — | 514 | — | 514 | ||||||||||||
Cash equivalents and other | 3 | 660 | — | 663 | ||||||||||||
Real estate investments | 293 | — | 1,121 | 1,414 | ||||||||||||
Private equity | — | — | 570 | 570 | ||||||||||||
Total | $ | 3,070 | $ | 4,886 | $ | 1,691 | $ | 9,647 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (2 | ) | $ | — | $ | — | $ | (2 | ) | ||||||
Total | $ | 3,068 | $ | 4,886 | $ | 1,691 | $ | 9,645 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 1,433 | $ | 839 | $ | — | $ | 2,272 | ||||||||
International equity* | 1,101 | 1,018 | — | 2,119 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 599 | — | 599 | ||||||||||||
Mortgage- and asset-backed securities | — | 156 | — | 156 | ||||||||||||
Corporate bonds | — | 978 | — | 978 | ||||||||||||
Pooled funds | — | 471 | — | 471 | ||||||||||||
Cash equivalents and other | 1 | 223 | — | 224 | ||||||||||||
Real estate investments | 260 | — | 1,000 | 1,260 | ||||||||||||
Private equity | — | — | 571 | 571 | ||||||||||||
Total | $ | 2,795 | $ | 4,284 | $ | 1,571 | $ | 8,650 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (3 | ) | $ | — | $ | (3 | ) | ||||||
Total | $ | 2,795 | $ | 4,281 | $ | 1,571 | $ | 8,647 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 1,000 | $ | 571 | $ | 841 | $ | 593 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 79 | 51 | 74 | 8 | ||||||||||||
Related to investments sold during the year | 33 | (16 | ) | 30 | 51 | |||||||||||
Total return on investments | 112 | 35 | 104 | 59 | ||||||||||||
Purchases, sales, and settlements | 9 | (36 | ) | 55 | (81 | ) | ||||||||||
Ending balance | $ | 1,121 | $ | 570 | $ | 1,000 | $ | 571 | ||||||||
Other Postretirement Benefits [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Other regulatory assets, deferred | $ | 387 | $ | 109 | ||||||||||||
Other current liabilities | (4 | ) | (4 | ) | ||||||||||||
Employee benefit obligations | (1,082 | ) | (777 | ) | ||||||||||||
Other regulatory liabilities, deferred | (21 | ) | (36 | ) | ||||||||||||
Accumulated OCI | 8 | 1 | ||||||||||||||
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 21 | $ | 24 | $ | 21 | ||||||||||
Interest cost | 79 | 74 | 85 | |||||||||||||
Expected return on plan assets | (59 | ) | (56 | ) | (60 | ) | ||||||||||
Net amortization | 6 | 21 | 20 | |||||||||||||
Net periodic postretirement benefit cost | $ | 47 | $ | 63 | $ | 66 | ||||||||||
Fair values of benefit plan assets | Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | Total | |||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | |||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 147 | $ | 56 | $ | — | $ | 203 | ||||||||
International equity* | 36 | 67 | — | 103 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 29 | — | 29 | ||||||||||||
Mortgage- and asset-backed securities | — | 6 | — | 6 | ||||||||||||
Corporate bonds | — | 39 | — | 39 | ||||||||||||
Pooled funds | — | 41 | — | 41 | ||||||||||||
Cash equivalents and other | 9 | 27 | — | 36 | ||||||||||||
Trust-owned life insurance | — | 381 | — | 381 | ||||||||||||
Real estate investments | 11 | — | 37 | 48 | ||||||||||||
Private equity | — | — | 19 | 19 | ||||||||||||
Total | $ | 203 | $ | 646 | $ | 56 | $ | 905 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 157 | $ | 45 | $ | — | $ | 202 | ||||||||
International equity* | 39 | 82 | — | 121 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 34 | — | 34 | ||||||||||||
Mortgage- and asset-backed securities | — | 6 | — | 6 | ||||||||||||
Corporate bonds | — | 35 | — | 35 | ||||||||||||
Pooled funds | — | 46 | — | 46 | ||||||||||||
Cash equivalents and other | — | 19 | — | 19 | ||||||||||||
Trust-owned life insurance | — | 369 | — | 369 | ||||||||||||
Real estate investments | 10 | — | 36 | 46 | ||||||||||||
Private equity | — | — | 20 | 20 | ||||||||||||
Total | $ | 206 | $ | 636 | $ | 56 | $ | 898 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 36 | $ | 20 | $ | 30 | $ | 21 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 1 | 1 | 3 | — | ||||||||||||
Related to investments sold during the year | — | (1 | ) | 1 | 2 | |||||||||||
Total return on investments | 1 | — | 4 | 2 | ||||||||||||
Purchases, sales, and settlements | — | (1 | ) | 2 | (3 | ) | ||||||||||
Ending balance | $ | 37 | $ | 19 | $ | 36 | $ | 20 | ||||||||
Alabama Power [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%. | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.18 | % | 5.02 | % | 4.27 | % | ||||||||||
Other postretirement benefit plans | 4.04 | 4.86 | 4.06 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 7.34 | 7.36 | 7.19 | |||||||||||||
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | |||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
Effect of 1% annual increase or decrease in assumed medical care cost on APBO and service and interest cost components | An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | |||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in millions) | ||||||||||||||||
Benefit obligation | $ | 34 | $ | (29 | ) | |||||||||||
Service and interest costs | 1 | (1 | ) | |||||||||||||
Changes in projected benefit obligations and fair value of plan assets | Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 2,112 | $ | 2,218 | ||||||||||||
Service cost | 48 | 52 | ||||||||||||||
Interest cost | 103 | 93 | ||||||||||||||
Benefits paid | (100 | ) | (93 | ) | ||||||||||||
Actuarial (gain) loss | 429 | (158 | ) | |||||||||||||
Balance at end of year | 2,592 | 2,112 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 2,278 | 2,077 | ||||||||||||||
Actual return on plan assets | 207 | 285 | ||||||||||||||
Employer contributions | 11 | 9 | ||||||||||||||
Benefits paid | (100 | ) | (93 | ) | ||||||||||||
Fair value of plan assets at end of year | 2,396 | 2,278 | ||||||||||||||
Prepaid pension costs (accrued liability) | $ | (196 | ) | $ | 166 | |||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Other regulatory assets, deferred | $ | 68 | $ | 6 | ||||||||||||
Other regulatory liabilities, deferred | (14 | ) | (21 | ) | ||||||||||||
Employee benefit obligations | (111 | ) | (42 | ) | ||||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 276 | ||||||||||||
Other regulatory assets, deferred | 827 | 476 | ||||||||||||||
Other current liabilities | (10 | ) | (9 | ) | ||||||||||||
Employee benefit obligations | (186 | ) | (101 | ) | ||||||||||||
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization | Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | 12 | $ | 19 | $ | 6 | ||||||||||
Net (gain) loss | 815 | 457 | 55 | |||||||||||||
Regulatory assets | $ | 827 | $ | 476 | ||||||||||||
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | 15 | $ | 19 | $ | 4 | ||||||||||
Net (gain) loss | 39 | (34 | ) | 2 | ||||||||||||
Net regulatory assets (liabilities) | $ | 54 | $ | (15 | ) | |||||||||||
Components of other comprehensive income along with changes in balances of regulatory assets and regulatory liabilities related to defined benefit pension plans | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Net regulatory assets (liabilities): | ||||||||||||||||
Beginning balance | $ | (15 | ) | $ | 89 | |||||||||||
Net gain (loss) | 73 | (99 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (4 | ) | (3 | ) | ||||||||||||
Amortization of net gain (loss) | — | (2 | ) | |||||||||||||
Total reclassification adjustments | (4 | ) | (5 | ) | ||||||||||||
Total change | 69 | (104 | ) | |||||||||||||
Ending balance | $ | 54 | $ | (15 | ) | |||||||||||
The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 476 | $ | 822 | ||||||||||||
Net (gain) loss | 389 | (287 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (7 | ) | (7 | ) | ||||||||||||
Amortization of net gain (loss) | (31 | ) | (52 | ) | ||||||||||||
Total reclassification adjustments | (38 | ) | (59 | ) | ||||||||||||
Total change | 351 | (346 | ) | |||||||||||||
Ending balance | $ | 827 | $ | 476 | ||||||||||||
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 48 | $ | 52 | $ | 44 | ||||||||||
Interest cost | 103 | 93 | 94 | |||||||||||||
Expected return on plan assets | (168 | ) | (157 | ) | (162 | ) | ||||||||||
Recognized net (gain) loss | 31 | 52 | 23 | |||||||||||||
Net amortization | 7 | 7 | 7 | |||||||||||||
Net periodic pension cost | $ | 21 | $ | 47 | $ | 6 | ||||||||||
Components of the other postretirement benefit plans' net periodic cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 5 | $ | 6 | $ | 5 | ||||||||||
Interest cost | 20 | 19 | 22 | |||||||||||||
Expected return on plan assets | (25 | ) | (23 | ) | (23 | ) | ||||||||||
Net amortization | 4 | 5 | 6 | |||||||||||||
Net periodic postretirement benefit cost | $ | 4 | $ | 7 | $ | 10 | ||||||||||
Estimated pension benefit payments | Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | |||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 31 | $ | (3 | ) | $ | 28 | |||||||||
2016 | 32 | (3 | ) | 29 | ||||||||||||
2017 | 32 | (4 | ) | 28 | ||||||||||||
2018 | 34 | (4 | ) | 30 | ||||||||||||
2019 | 34 | (4 | ) | 30 | ||||||||||||
2020 to 2024 | 172 | (22 | ) | 150 | ||||||||||||
At December 31, 2014, estimated benefit payments were as follows: | ||||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 127 | ||||||||||||||
2016 | 114 | |||||||||||||||
2017 | 120 | |||||||||||||||
2018 | 125 | |||||||||||||||
2019 | 129 | |||||||||||||||
2020 to 2024 | 708 | |||||||||||||||
Changes in the accumulated postretirement benefit obligations (APBO) and in fair value of plan assets | Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 431 | $ | 490 | ||||||||||||
Service cost | 5 | 6 | ||||||||||||||
Interest cost | 20 | 19 | ||||||||||||||
Benefits paid | (27 | ) | (24 | ) | ||||||||||||
Actuarial (gain) loss | 71 | (62 | ) | |||||||||||||
Retiree drug subsidy | 3 | 2 | ||||||||||||||
Balance at end of year | 503 | 431 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 389 | 343 | ||||||||||||||
Actual return on plan assets | 23 | 61 | ||||||||||||||
Employer contributions | 4 | 7 | ||||||||||||||
Benefits paid | (24 | ) | (22 | ) | ||||||||||||
Fair value of plan assets at end of year | 392 | 389 | ||||||||||||||
Accrued liability | $ | (111 | ) | $ | (42 | ) | ||||||||||
Composition of benefit plan assets along with targeted mix of assets | The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | |||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 48 | % | 48 | % | 47 | % | ||||||||||
International equity | 20 | 20 | 20 | |||||||||||||
Domestic fixed income | 24 | 26 | 27 | |||||||||||||
Special situations | 1 | — | — | |||||||||||||
Real estate investments | 4 | 4 | 4 | |||||||||||||
Private equity | 3 | 2 | 2 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
in Active Markets for Identical Assets | ||||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 421 | $ | 174 | $ | — | $ | 595 | ||||||||
International equity* | 264 | 244 | — | 508 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 173 | — | 173 | ||||||||||||
Mortgage- and asset-backed securities | — | 47 | — | 47 | ||||||||||||
Corporate bonds | — | 280 | — | 280 | ||||||||||||
Pooled funds | — | 127 | — | 127 | ||||||||||||
Cash equivalents and other | 1 | 163 | — | 164 | ||||||||||||
Real estate investments | 73 | — | 277 | 350 | ||||||||||||
Private equity | — | — | 141 | 141 | ||||||||||||
Total | $ | 759 | $ | 1,208 | $ | 418 | $ | 2,385 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
in Active Markets for Identical Assets | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 374 | $ | 219 | $ | — | $ | 593 | ||||||||
International equity* | 287 | 265 | — | 552 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 156 | — | 156 | ||||||||||||
Mortgage- and asset-backed securities | — | 41 | — | 41 | ||||||||||||
Corporate bonds | — | 255 | — | 255 | ||||||||||||
Pooled funds | — | 123 | — | 123 | ||||||||||||
Cash equivalents and other | — | 58 | — | 58 | ||||||||||||
Real estate investments | 68 | — | 261 | 329 | ||||||||||||
Private equity | — | — | 149 | 149 | ||||||||||||
Total | $ | 729 | $ | 1,117 | $ | 410 | $ | 2,256 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | ||||||
Total | $ | 729 | $ | 1,116 | $ | 410 | $ | 2,255 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 76 | $ | 8 | $ | — | $ | 84 | ||||||||
International equity* | 13 | 12 | — | 25 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 10 | — | 10 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 14 | — | 14 | ||||||||||||
Pooled funds | — | 6 | — | 6 | ||||||||||||
Cash equivalents and other | — | 8 | — | 8 | ||||||||||||
Trust-owned life insurance | — | 217 | — | 217 | ||||||||||||
Real estate investments | 5 | — | 13 | 18 | ||||||||||||
Private equity | — | — | 7 | 7 | ||||||||||||
Total | $ | 94 | $ | 277 | $ | 20 | $ | 391 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 67 | $ | 11 | $ | — | $ | 78 | ||||||||
International equity* | 14 | 13 | — | 27 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 17 | — | 17 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 12 | — | 12 | ||||||||||||
Pooled funds | — | 6 | — | 6 | ||||||||||||
Cash equivalents and other | — | 10 | — | 10 | ||||||||||||
Trust-owned life insurance | — | 211 | — | 211 | ||||||||||||
Real estate investments | 4 | — | 13 | 17 | ||||||||||||
Private equity | — | — | 7 | 7 | ||||||||||||
Total | $ | 85 | $ | 282 | $ | 20 | $ | 387 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 261 | $ | 149 | $ | 220 | $ | 155 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 6 | 5 | 19 | 2 | ||||||||||||
Related to investments sold during the year | 8 | (4 | ) | 8 | 13 | |||||||||||
Total return on investments | 14 | 1 | 27 | 15 | ||||||||||||
Purchases, sales, and settlements | 2 | (9 | ) | 14 | (21 | ) | ||||||||||
Ending balance | $ | 277 | $ | 141 | $ | 261 | $ | 149 | ||||||||
Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 13 | $ | 7 | $ | 11 | $ | 8 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | — | — | 1 | — | ||||||||||||
Related to investments sold during the year | — | — | — | — | ||||||||||||
Total return on investments | — | — | 1 | — | ||||||||||||
Purchases, sales, and settlements | — | — | 1 | (1 | ) | |||||||||||
Ending balance | $ | 13 | $ | 7 | $ | 13 | $ | 7 | ||||||||
Georgia Power [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.87%, respectively, and an annual salary increase of 3.84%. | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.18 | % | 5.02 | % | 4.27 | % | ||||||||||
Other postretirement benefit plans | 4.03 | 4.85 | 4.04 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 6.75 | 6.74 | 7.24 | |||||||||||||
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | |||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
Effect of 1% annual increase or decrease in assumed medical care cost on APBO and service and interest cost components | An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | |||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in millions) | ||||||||||||||||
Benefit obligation | $ | 69 | $ | (58 | ) | |||||||||||
Service and interest costs | 3 | (2 | ) | |||||||||||||
Changes in projected benefit obligations and fair value of plan assets | Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 3,116 | $ | 3,312 | ||||||||||||
Service cost | 62 | 69 | ||||||||||||||
Interest cost | 153 | 138 | ||||||||||||||
Benefits paid | (149 | ) | (141 | ) | ||||||||||||
Actuarial (gain) loss | 599 | (262 | ) | |||||||||||||
Balance at end of year | 3,781 | 3,116 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 3,085 | 2,827 | ||||||||||||||
Actual return on plan assets | 285 | 387 | ||||||||||||||
Employer contributions | 162 | 12 | ||||||||||||||
Benefits paid | (149 | ) | (141 | ) | ||||||||||||
Fair value of plan assets at end of year | 3,383 | 3,085 | ||||||||||||||
Accrued liability | $ | (398 | ) | $ | (31 | ) | ||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 118 | ||||||||||||
Other regulatory assets, deferred | 1,102 | 610 | ||||||||||||||
Current liabilities, other | (12 | ) | (12 | ) | ||||||||||||
Employee benefit obligations | (386 | ) | (137 | ) | ||||||||||||
Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Other regulatory assets, deferred | $ | 213 | $ | 69 | ||||||||||||
Employee benefit obligations | (469 | ) | (316 | ) | ||||||||||||
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization | Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | (5 | ) | $ | (4 | ) | $ | — | ||||||||
Net (gain) loss | 218 | 73 | 11 | |||||||||||||
Regulatory assets | $ | 213 | $ | 69 | ||||||||||||
Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | ||||||||||||||||
2014 | 2013 | Estimated | ||||||||||||||
Amortization | ||||||||||||||||
in 2015 | ||||||||||||||||
(in millions) | ||||||||||||||||
Prior service cost | $ | 17 | $ | 26 | $ | 9 | ||||||||||
Net (gain) loss | 1,085 | 584 | 76 | |||||||||||||
Regulatory assets | $ | 1,102 | $ | 610 | ||||||||||||
Components of other comprehensive income along with changes in balances of regulatory assets and regulatory liabilities related to defined benefit pension plans | The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 610 | $ | 1,132 | ||||||||||||
Net (gain) loss | 543 | (438 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (10 | ) | (10 | ) | ||||||||||||
Amortization of net gain (loss) | (41 | ) | (74 | ) | ||||||||||||
Total reclassification adjustments | (51 | ) | (84 | ) | ||||||||||||
Total change | 492 | (522 | ) | |||||||||||||
Ending balance | $ | 1,102 | $ | 610 | ||||||||||||
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 62 | $ | 69 | $ | 60 | ||||||||||
Interest cost | 153 | 138 | 141 | |||||||||||||
Expected return on plan assets | (228 | ) | (212 | ) | (221 | ) | ||||||||||
Recognized net loss | 41 | 74 | 33 | |||||||||||||
Net amortization | 10 | 10 | 12 | |||||||||||||
Net periodic pension cost | $ | 38 | $ | 79 | $ | 25 | ||||||||||
Components of the other postretirement benefit plans' net periodic cost were as follows: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in millions) | ||||||||||||||||
Service cost | $ | 6 | $ | 7 | $ | 7 | ||||||||||
Interest cost | 34 | 31 | 37 | |||||||||||||
Expected return on plan assets | (25 | ) | (24 | ) | (29 | ) | ||||||||||
Net amortization | 2 | 12 | 10 | |||||||||||||
Net periodic postretirement benefit cost | $ | 17 | $ | 26 | $ | 25 | ||||||||||
Estimated pension benefit payments | At December 31, 2014, estimated benefit payments were as follows: | |||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 199 | ||||||||||||||
2016 | 169 | |||||||||||||||
2017 | 177 | |||||||||||||||
2018 | 183 | |||||||||||||||
2019 | 190 | |||||||||||||||
2020 to 2024 | 1,042 | |||||||||||||||
Changes in the accumulated postretirement benefit obligations (APBO) and in fair value of plan assets | Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 723 | $ | 800 | ||||||||||||
Service cost | 6 | 7 | ||||||||||||||
Interest cost | 34 | 31 | ||||||||||||||
Benefits paid | (44 | ) | (45 | ) | ||||||||||||
Actuarial (gain) loss | 142 | (73 | ) | |||||||||||||
Retiree drug subsidy | 3 | 3 | ||||||||||||||
Balance at end of year | 864 | 723 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 407 | 382 | ||||||||||||||
Actual return on plan assets | 21 | 56 | ||||||||||||||
Employer contributions | 8 | 11 | ||||||||||||||
Benefits paid | (41 | ) | (42 | ) | ||||||||||||
Fair value of plan assets at end of year | 395 | 407 | ||||||||||||||
Accrued liability | $ | (469 | ) | $ | (316 | ) | ||||||||||
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The changes in the balance of regulatory assets related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in millions) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 69 | $ | 187 | ||||||||||||
Net (gain) loss | 146 | (106 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of transition obligation | — | (4 | ) | |||||||||||||
Amortization of net gain (loss) | (2 | ) | (8 | ) | ||||||||||||
Total reclassification adjustments | (2 | ) | (12 | ) | ||||||||||||
Total change | 144 | (118 | ) | |||||||||||||
Ending balance | $ | 213 | $ | 69 | ||||||||||||
Summary of estimation of future benefit payments and subsidy receipts based on assumptions used to measure accumulated benefit obligation for postretirement plans | Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | |||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in millions) | ||||||||||||||||
2015 | $ | 53 | $ | (4 | ) | $ | 49 | |||||||||
2016 | 56 | (5 | ) | 51 | ||||||||||||
2017 | 57 | (5 | ) | 52 | ||||||||||||
2018 | 59 | (6 | ) | 53 | ||||||||||||
2019 | 59 | (6 | ) | 53 | ||||||||||||
2020 to 2024 | 289 | (32 | ) | 257 | ||||||||||||
Composition of benefit plan assets along with targeted mix of assets | The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | |||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 40 | % | 38 | % | 36 | % | ||||||||||
International equity | 21 | 26 | 30 | |||||||||||||
Domestic fixed income | 24 | 24 | 21 | |||||||||||||
Global fixed income | 8 | 7 | 8 | |||||||||||||
Special situations | 1 | — | — | |||||||||||||
Real estate investments | 4 | 4 | 3 | |||||||||||||
Private equity | 2 | 1 | 2 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 595 | $ | 246 | $ | — | $ | 841 | ||||||||
International equity* | 373 | 344 | — | 717 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 244 | — | 244 | ||||||||||||
Mortgage- and asset-backed securities | — | 66 | — | 66 | ||||||||||||
Corporate bonds | — | 398 | — | 398 | ||||||||||||
Pooled funds | — | 179 | — | 179 | ||||||||||||
Cash equivalents and other | 1 | 230 | — | 231 | ||||||||||||
Real estate investments | 102 | — | 391 | 493 | ||||||||||||
Private equity | — | — | 199 | 199 | ||||||||||||
Total | $ | 1,071 | $ | 1,707 | $ | 590 | $ | 3,368 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (1 | ) | $ | — | $ | — | $ | (1 | ) | ||||||
Total | $ | 1,070 | $ | 1,707 | $ | 590 | $ | 3,367 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 506 | $ | 296 | $ | — | $ | 802 | ||||||||
International equity* | 389 | 359 | — | 748 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 212 | — | 212 | ||||||||||||
Mortgage- and asset-backed securities | — | 55 | — | 55 | ||||||||||||
Corporate bonds | — | 346 | — | 346 | ||||||||||||
Pooled funds | — | 166 | — | 166 | ||||||||||||
Cash equivalents and other | — | 79 | — | 79 | ||||||||||||
Real estate investments | 92 | — | 353 | 445 | ||||||||||||
Private equity | — | — | 202 | 202 | ||||||||||||
Total | $ | 987 | $ | 1,513 | $ | 555 | $ | 3,055 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | ||||||
Total | $ | 987 | $ | 1,512 | $ | 555 | $ | 3,054 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 53 | $ | 40 | $ | — | $ | 93 | ||||||||
International equity* | 11 | 45 | — | 56 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 7 | — | 7 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 12 | — | 12 | ||||||||||||
Pooled funds | — | 29 | — | 29 | ||||||||||||
Cash equivalents and other | 8 | 11 | — | 19 | ||||||||||||
Trust-owned life insurance | — | 162 | — | 162 | ||||||||||||
Real estate investments | 3 | — | 12 | 15 | ||||||||||||
Private equity | — | — | 6 | 6 | ||||||||||||
Total | $ | 75 | $ | 308 | $ | 18 | $ | 401 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 74 | $ | 25 | $ | — | $ | 99 | ||||||||
International equity* | 12 | 57 | — | 69 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 7 | — | 7 | ||||||||||||
Mortgage- and asset-backed securities | — | 2 | — | 2 | ||||||||||||
Corporate bonds | — | 11 | — | 11 | ||||||||||||
Pooled funds | — | 34 | — | 34 | ||||||||||||
Cash equivalents and other | — | 6 | — | 6 | ||||||||||||
Trust-owned life insurance | — | 158 | — | 158 | ||||||||||||
Real estate investments | 3 | — | 11 | 14 | ||||||||||||
Private equity | — | — | 6 | 6 | ||||||||||||
Total | $ | 89 | $ | 300 | $ | 17 | $ | 406 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 11 | $ | 6 | $ | 10 | $ | 7 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 1 | — | 1 | — | ||||||||||||
Related to investments sold during the year | — | — | — | — | ||||||||||||
Total return on investments | 1 | — | 1 | — | ||||||||||||
Purchases, sales, and settlements | — | — | — | (1 | ) | |||||||||||
Ending balance | $ | 12 | $ | 6 | $ | 11 | $ | 6 | ||||||||
Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in millions) | ||||||||||||||||
Beginning balance | $ | 353 | $ | 202 | $ | 299 | $ | 211 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 23 | 15 | 25 | 3 | ||||||||||||
Related to investments sold during the year | 12 | (6 | ) | 10 | 17 | |||||||||||
Total return on investments | 35 | 9 | 35 | 20 | ||||||||||||
Purchases, sales, and settlements | 3 | (12 | ) | 19 | (29 | ) | ||||||||||
Ending balance | $ | 391 | $ | 199 | $ | 353 | $ | 202 | ||||||||
Gulf Power [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.88%, respectively, and an annual salary increase of 3.84%. | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.18 | % | 5.02 | % | 4.27 | % | ||||||||||
Other postretirement benefit plans | 4.04 | 4.86 | 4.06 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 8.08 | 8.04 | 8.02 | |||||||||||||
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | |||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
Effect of 1% annual increase or decrease in assumed medical care cost on APBO and service and interest cost components | An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | |||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in thousands) | ||||||||||||||||
Benefit obligation | $ | 3,934 | $ | (3,334 | ) | |||||||||||
Service and interest costs | 157 | (133 | ) | |||||||||||||
Changes in projected benefit obligations and fair value of plan assets | Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 395,328 | $ | 413,501 | ||||||||||||
Service cost | 10,181 | 11,128 | ||||||||||||||
Interest cost | 19,433 | 17,321 | ||||||||||||||
Benefits paid | (15,635 | ) | (14,831 | ) | ||||||||||||
Actuarial (gain) loss | 81,254 | (31,791 | ) | |||||||||||||
Balance at end of year | 490,561 | 395,328 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 385,639 | 350,260 | ||||||||||||||
Actual return on plan assets | 33,512 | 49,076 | ||||||||||||||
Employer contributions | 31,251 | 1,134 | ||||||||||||||
Benefits paid | (15,635 | ) | (14,831 | ) | ||||||||||||
Fair value of plan assets at end of year | 434,767 | 385,639 | ||||||||||||||
Accrued liability | $ | (55,794 | ) | $ | (9,689 | ) | ||||||||||
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization | Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | 3,286 | $ | 4,401 | $ | 1,115 | ||||||||||
Net (gain) loss | 142,529 | 70,879 | 9,281 | |||||||||||||
Regulatory assets | $ | 145,815 | $ | 75,280 | ||||||||||||
Components of other comprehensive income along with changes in balances of regulatory assets and regulatory liabilities related to defined benefit pension plans | The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 75,280 | $ | 139,261 | ||||||||||||
Net (gain) loss | 76,209 | (54,432 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1,115 | ) | (1,164 | ) | ||||||||||||
Amortization of net gain (loss) | (4,559 | ) | (8,385 | ) | ||||||||||||
Total reclassification adjustments | (5,674 | ) | (9,549 | ) | ||||||||||||
Total change | 70,535 | (63,981 | ) | |||||||||||||
Ending balance | $ | 145,815 | $ | 75,280 | ||||||||||||
Estimated pension benefit payments | At December 31, 2014, estimated benefit payments were as follows: | |||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 22,002 | ||||||||||||||
2016 | 18,683 | |||||||||||||||
2017 | 19,950 | |||||||||||||||
2018 | 21,019 | |||||||||||||||
2019 | 22,229 | |||||||||||||||
2020 to 2024 | 129,877 | |||||||||||||||
Changes in the accumulated postretirement benefit obligations (APBO) and in fair value of plan assets | Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 68,579 | $ | 75,395 | ||||||||||||
Service cost | 1,163 | 1,355 | ||||||||||||||
Interest cost | 3,235 | 2,982 | ||||||||||||||
Benefits paid | (4,061 | ) | (3,583 | ) | ||||||||||||
Actuarial (gain) loss | 11,317 | (7,900 | ) | |||||||||||||
Plan amendment | (2,089 | ) | — | |||||||||||||
Retiree drug subsidy | 357 | 330 | ||||||||||||||
Balance at end of year | 78,501 | 68,579 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 17,474 | 16,227 | ||||||||||||||
Actual return on plan assets | 1,578 | 2,119 | ||||||||||||||
Employer contributions | 2,846 | 2,381 | ||||||||||||||
Benefits paid | (3,704 | ) | (3,253 | ) | ||||||||||||
Fair value of plan assets at end of year | 18,194 | 17,474 | ||||||||||||||
Accrued liability | $ | (60,307 | ) | $ | (51,105 | ) | ||||||||||
Amounts included in accumulated other comprehensive income and regulatory assets related to other postretirement benefit plans | Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | (2,137 | ) | $ | 138 | $ | 25 | |||||||||
Net (gain) loss | 3,947 | (7,122 | ) | — | ||||||||||||
Net regulatory assets (liabilities) | $ | 1,810 | $ | (6,984 | ) | |||||||||||
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Net regulatory assets (liabilities): | ||||||||||||||||
Beginning balance | $ | (6,984 | ) | $ | 2,169 | |||||||||||
Net (gain) loss | 11,045 | (8,967 | ) | |||||||||||||
Change in prior service costs | (2,089 | ) | — | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (186 | ) | (186 | ) | ||||||||||||
Amortization of net gain (loss) | 24 | — | ||||||||||||||
Total reclassification adjustments | (162 | ) | (186 | ) | ||||||||||||
Total change | 8,794 | (9,153 | ) | |||||||||||||
Ending balance | $ | 1,810 | $ | (6,984 | ) | |||||||||||
Summary of estimation of future benefit payments and subsidy receipts based on assumptions used to measure accumulated benefit obligation for postretirement plans | Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | |||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 4,694 | $ | (431 | ) | $ | 4,263 | |||||||||
2016 | 4,982 | (480 | ) | 4,502 | ||||||||||||
2017 | 5,136 | (535 | ) | 4,601 | ||||||||||||
2018 | 5,300 | (594 | ) | 4,706 | ||||||||||||
2019 | 5,326 | (660 | ) | 4,666 | ||||||||||||
2020 to 2024 | 27,399 | (3,430 | ) | 23,969 | ||||||||||||
Composition of benefit plan assets along with targeted mix of assets | The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | |||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 25 | % | 29 | % | 30 | % | ||||||||||
International equity | 24 | 22 | 24 | |||||||||||||
Domestic fixed income | 25 | 29 | 25 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Gulf Power [Member] | Pension Plans [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 11,533 | ||||||||||||
Other regulatory assets, deferred | 145,815 | 75,280 | ||||||||||||||
Current liabilities, other | (1,307 | ) | (1,183 | ) | ||||||||||||
Employee benefit obligations | (54,487 | ) | (20,039 | ) | ||||||||||||
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 10,181 | $ | 11,128 | $ | 9,101 | ||||||||||
Interest cost | 19,433 | 17,321 | 17,199 | |||||||||||||
Expected return on plan assets | (28,468 | ) | (26,435 | ) | (25,932 | ) | ||||||||||
Recognized net (gain) loss | 4,559 | 8,385 | 3,913 | |||||||||||||
Net amortization | 1,115 | 1,164 | 1,262 | |||||||||||||
Net periodic pension cost | $ | 6,820 | $ | 11,563 | $ | 5,543 | ||||||||||
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 76,460 | $ | 31,588 | $ | — | $ | 108,048 | ||||||||
International equity* | 47,988 | 44,223 | — | 92,211 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 31,372 | — | 31,372 | ||||||||||||
Mortgage- and asset-backed securities | — | 8,438 | — | 8,438 | ||||||||||||
Corporate bonds | — | 50,931 | — | 50,931 | ||||||||||||
Pooled funds | — | 23,063 | — | 23,063 | ||||||||||||
Cash equivalents and other | 130 | 29,597 | — | 29,727 | ||||||||||||
Real estate investments | 13,154 | — | 50,281 | 63,435 | ||||||||||||
Private equity | — | — | 25,573 | 25,573 | ||||||||||||
Total | $ | 137,732 | $ | 219,212 | $ | 75,854 | $ | 432,798 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (87 | ) | $ | — | $ | — | $ | (87 | ) | ||||||
Total | $ | 137,645 | $ | 219,212 | $ | 75,854 | $ | 432,711 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 63,269 | $ | 37,037 | $ | — | $ | 100,306 | ||||||||
International equity* | 48,606 | 44,941 | — | 93,547 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 26,461 | — | 26,461 | ||||||||||||
Mortgage- and asset-backed securities | — | 6,873 | — | 6,873 | ||||||||||||
Corporate bonds | — | 43,222 | — | 43,222 | ||||||||||||
Pooled funds | — | 20,810 | — | 20,810 | ||||||||||||
Cash equivalents and other | 38 | 9,851 | — | 9,889 | ||||||||||||
Real estate investments | 11,493 | — | 44,139 | 55,632 | ||||||||||||
Private equity | — | — | 25,201 | 25,201 | ||||||||||||
Total | $ | 123,406 | $ | 189,195 | $ | 69,340 | $ | 381,941 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (115 | ) | $ | — | $ | (115 | ) | ||||||
Total | $ | 123,406 | $ | 189,080 | $ | 69,340 | $ | 381,826 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 44,139 | $ | 25,201 | $ | 37,039 | $ | 26,129 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 4,263 | 2,697 | 3,357 | 376 | ||||||||||||
Related to investments sold during the year | 1,488 | (727 | ) | 1,310 | 2,282 | |||||||||||
Total return on investments | 5,751 | 1,970 | 4,667 | 2,658 | ||||||||||||
Purchases, sales, and settlements | 391 | (1,598 | ) | 2,433 | (3,586 | ) | ||||||||||
Ending balance | $ | 50,281 | $ | 25,573 | $ | 44,139 | $ | 25,201 | ||||||||
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Other regulatory assets, deferred | $ | 6,100 | $ | — | ||||||||||||
Current liabilities, other | (639 | ) | (687 | ) | ||||||||||||
Other regulatory liabilities, deferred | (4,290 | ) | (6,984 | ) | ||||||||||||
Employee benefit obligations | (59,668 | ) | (50,418 | ) | ||||||||||||
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 1,163 | $ | 1,355 | $ | 1,167 | ||||||||||
Interest cost | 3,235 | 2,982 | 3,367 | |||||||||||||
Expected return on plan assets | (1,306 | ) | (1,238 | ) | (1,311 | ) | ||||||||||
Net amortization | 162 | 186 | 379 | |||||||||||||
Net periodic postretirement benefit cost | $ | 3,254 | $ | 3,285 | $ | 3,602 | ||||||||||
Fair values of benefit plan assets | The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 3,105 | $ | 1,283 | $ | — | $ | 4,388 | ||||||||
International equity* | 1,949 | 1,798 | — | 3,747 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 1,274 | — | 1,274 | ||||||||||||
Mortgage- and asset-backed securities | — | 342 | — | 342 | ||||||||||||
Corporate bonds | — | 2,071 | — | 2,071 | ||||||||||||
Pooled funds | — | 937 | — | 937 | ||||||||||||
Cash equivalents and other | 510 | 1,203 | — | 1,713 | ||||||||||||
Real estate investments | 534 | — | 2,042 | 2,576 | ||||||||||||
Private equity | — | — | 1,039 | 1,039 | ||||||||||||
Total | $ | 6,098 | $ | 8,908 | $ | 3,081 | $ | 18,087 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (4 | ) | $ | — | $ | — | $ | (4 | ) | ||||||
Total | $ | 6,094 | $ | 8,908 | $ | 3,081 | $ | 18,083 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 2,778 | $ | 1,628 | $ | — | $ | 4,406 | ||||||||
International equity* | 2,136 | 1,973 | — | 4,109 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 1,161 | — | 1,161 | ||||||||||||
Mortgage- and asset-backed securities | — | 303 | — | 303 | ||||||||||||
Corporate bonds | — | 1,897 | — | 1,897 | ||||||||||||
Pooled funds | — | 1,417 | — | 1,417 | ||||||||||||
Cash equivalents and other | 1 | 433 | — | 434 | ||||||||||||
Real estate investments | 504 | — | 1,939 | 2,443 | ||||||||||||
Private equity | — | — | 1,108 | 1,108 | ||||||||||||
Total | $ | 5,419 | $ | 8,812 | $ | 3,047 | $ | 17,278 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (5 | ) | $ | — | $ | (5 | ) | ||||||
Total | $ | 5,419 | $ | 8,807 | $ | 3,047 | $ | 17,273 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate | Private | Real Estate | Private | |||||||||||||
Investments | Equity | Investments | Equity | |||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 1,939 | $ | 1,108 | $ | 1,667 | $ | 1,155 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 27 | 26 | 108 | 16 | ||||||||||||
Related to investments sold during the year | 60 | (30 | ) | 57 | 104 | |||||||||||
Total return on investments | 87 | (4 | ) | 165 | 120 | |||||||||||
Purchases, sales, and settlements | 16 | (65 | ) | 107 | (167 | ) | ||||||||||
Ending balance | $ | 2,042 | $ | 1,039 | $ | 1,939 | $ | 1,108 | ||||||||
Mississippi Power [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Weighted average rates assumed in actuarial calculations used to determine both benefit obligations as of measurement date and net periodic costs for pension and other postretirement benefit plans | The weighted average rates assumed in the actuarial calculations used to determine both the benefit obligations as of the measurement date and the net periodic costs for the pension and other postretirement benefit plans for the following year are presented below. Net periodic benefit costs were calculated in 2011 for the 2012 plan year using discount rates for the pension plans and the other postretirement benefit plans of 4.98% and 4.87%, respectively, and an annual salary increase of 3.84%. | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Discount rate: | ||||||||||||||||
Pension plans | 4.17 | % | 5.01 | % | 4.26 | % | ||||||||||
Other postretirement benefit plans | 4.03 | 4.85 | 4.04 | |||||||||||||
Annual salary increase | 3.59 | 3.59 | 3.59 | |||||||||||||
Long-term return on plan assets: | ||||||||||||||||
Pension plans | 8.2 | 8.2 | 8.2 | |||||||||||||
Other postretirement benefit plans | 7.3 | 7.04 | 6.96 | |||||||||||||
Schedule of Health Care Cost Trend Rates | The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2014 were as follows: | |||||||||||||||
Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | ||||||||||||||
Pre-65 | 9 | % | 4.5 | % | 2024 | |||||||||||
Post-65 medical | 6 | 4.5 | 2024 | |||||||||||||
Post-65 prescription | 6.75 | 4.5 | 2024 | |||||||||||||
Effect of 1% annual increase or decrease in assumed medical care cost on APBO and service and interest cost components | An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO and the service and interest cost components at December 31, 2014 as follows: | |||||||||||||||
1 Percent | 1 Percent | |||||||||||||||
Increase | Decrease | |||||||||||||||
(in thousands) | ||||||||||||||||
Benefit obligation | $ | 6,241 | $ | (5,289 | ) | |||||||||||
Service and interest costs | 250 | (212 | ) | |||||||||||||
Changes in projected benefit obligations and fair value of plan assets | Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 409,395 | $ | 432,553 | ||||||||||||
Service cost | 10,123 | 11,067 | ||||||||||||||
Interest cost | 20,093 | 18,062 | ||||||||||||||
Benefits paid | (17,499 | ) | (16,207 | ) | ||||||||||||
Actuarial (gain) loss | 90,735 | (36,080 | ) | |||||||||||||
Balance at end of year | 512,847 | 409,395 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 387,403 | 351,749 | ||||||||||||||
Actual return on plan assets | 40,051 | 49,431 | ||||||||||||||
Employer contributions | 35,526 | 2,430 | ||||||||||||||
Benefits paid | (17,499 | ) | (16,207 | ) | ||||||||||||
Fair value of plan assets at end of year | 445,481 | 387,403 | ||||||||||||||
Accrued liability | $ | (67,366 | ) | $ | (21,992 | ) | ||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's other postretirement benefit plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Other regulatory assets, deferred | $ | 18,345 | $ | 5,227 | ||||||||||||
Other regulatory liabilities, deferred | (2,011 | ) | (3,111 | ) | ||||||||||||
Employee benefit obligations | (71,532 | ) | (57,663 | ) | ||||||||||||
Components of other comprehensive income along with changes in balances of regulatory assets and regulatory liabilities related to defined benefit pension plans | The changes in the balance of regulatory assets related to the defined benefit pension plans for the years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Regulatory assets: | ||||||||||||||||
Beginning balance | $ | 77,572 | $ | 146,838 | ||||||||||||
Net (gain) loss | 79,425 | (58,662 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | (1,088 | ) | (1,143 | ) | ||||||||||||
Amortization of net gain (loss) | (4,937 | ) | (9,461 | ) | ||||||||||||
Total reclassification adjustments | (6,025 | ) | (10,604 | ) | ||||||||||||
Total change | 73,400 | (69,266 | ) | |||||||||||||
Ending balance | $ | 150,972 | $ | 77,572 | ||||||||||||
Estimated pension benefit payments | At December 31, 2014, estimated benefit payments were as follows: | |||||||||||||||
Benefit | ||||||||||||||||
Payments | ||||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 23,304 | ||||||||||||||
2016 | 19,551 | |||||||||||||||
2017 | 20,816 | |||||||||||||||
2018 | 21,905 | |||||||||||||||
2019 | 23,337 | |||||||||||||||
2020 to 2024 | 135,320 | |||||||||||||||
Changes in the accumulated postretirement benefit obligations (APBO) and in fair value of plan assets | Changes in the APBO and in the fair value of plan assets during the plan years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
Benefit obligation at beginning of year | $ | 80,940 | $ | 91,783 | ||||||||||||
Service cost | 1,025 | 1,151 | ||||||||||||||
Interest cost | 3,812 | 3,619 | ||||||||||||||
Benefits paid | (4,887 | ) | (4,080 | ) | ||||||||||||
Actuarial (gain) loss | 14,259 | (11,959 | ) | |||||||||||||
Retiree drug subsidy | 506 | 426 | ||||||||||||||
Balance at end of year | 95,655 | 80,940 | ||||||||||||||
Change in plan assets | ||||||||||||||||
Fair value of plan assets at beginning of year | 23,277 | 21,990 | ||||||||||||||
Actual return on plan assets | 1,814 | 2,379 | ||||||||||||||
Employer contributions | 3,413 | 2,562 | ||||||||||||||
Benefits paid | (4,381 | ) | (3,654 | ) | ||||||||||||
Fair value of plan assets at end of year | 24,123 | 23,277 | ||||||||||||||
Accrued liability | $ | (71,532 | ) | $ | (57,663 | ) | ||||||||||
Components of other comprehensive income along with changes in balance of regulatory assets related to other postretirement benefit plans | The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2014 and 2013 are presented in the following table: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Net regulatory assets (liabilities): | ||||||||||||||||
Beginning balance | $ | 2,116 | $ | 15,454 | ||||||||||||
Net (gain) loss | 14,030 | (12,867 | ) | |||||||||||||
Reclassification adjustments: | ||||||||||||||||
Amortization of prior service costs | 188 | 188 | ||||||||||||||
Amortization of net gain (loss) | — | (659 | ) | |||||||||||||
Total reclassification adjustments | 188 | (471 | ) | |||||||||||||
Total change | 14,218 | (13,338 | ) | |||||||||||||
Ending balance | $ | 16,334 | $ | 2,116 | ||||||||||||
Summary of estimation of future benefit payments and subsidy receipts based on assumptions used to measure accumulated benefit obligation for postretirement plans | Estimated benefit payments are reduced by drug subsidy receipts expected as a result of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 as follows: | |||||||||||||||
Benefit | Subsidy | Total | ||||||||||||||
Payments | Receipts | |||||||||||||||
(in thousands) | ||||||||||||||||
2015 | $ | 5,387 | $ | (512 | ) | $ | 4,875 | |||||||||
2016 | 5,632 | (566 | ) | 5,066 | ||||||||||||
2017 | 5,911 | (622 | ) | 5,289 | ||||||||||||
2018 | 6,185 | (680 | ) | 5,505 | ||||||||||||
2019 | 6,475 | (735 | ) | 5,740 | ||||||||||||
2020 to 2024 | 34,139 | (3,744 | ) | 30,395 | ||||||||||||
Composition of benefit plan assets along with targeted mix of assets | The composition of the Company's pension plan and other postretirement benefit plan assets as of December 31, 2014 and 2013, along with the targeted mix of assets for each plan, is presented below: | |||||||||||||||
Target | 2014 | 2013 | ||||||||||||||
Pension plan assets: | ||||||||||||||||
Domestic equity | 26 | % | 30 | % | 31 | % | ||||||||||
International equity | 25 | 23 | 25 | |||||||||||||
Fixed income | 23 | 27 | 23 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 14 | 14 | 14 | |||||||||||||
Private equity | 9 | 5 | 6 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Other postretirement benefit plan assets: | ||||||||||||||||
Domestic equity | 21 | % | 24 | % | 25 | % | ||||||||||
International equity | 21 | 19 | 20 | |||||||||||||
Domestic fixed income | 37 | 41 | 38 | |||||||||||||
Special situations | 3 | 1 | 1 | |||||||||||||
Real estate investments | 11 | 11 | 11 | |||||||||||||
Private equity | 7 | 4 | 5 | |||||||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Mississippi Power [Member] | Pension Plans [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Amounts recognized in balance sheets related to benefit plans | Amounts recognized in the balance sheets at December 31, 2014 and 2013 related to the Company's pension plans consist of the following: | |||||||||||||||
2014 | 2013 | |||||||||||||||
(in thousands) | ||||||||||||||||
Prepaid pension costs | $ | — | $ | 5,698 | ||||||||||||
Other regulatory assets, deferred | 150,972 | 77,572 | ||||||||||||||
Other current liabilities | (2,337 | ) | (2,134 | ) | ||||||||||||
Employee benefit obligations | (65,029 | ) | (25,556 | ) | ||||||||||||
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization | Presented below are the amounts included in regulatory assets at December 31, 2014 and 2013 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | 3,030 | $ | 4,118 | $ | 1,088 | ||||||||||
Net (gain) loss | 147,942 | 73,454 | 10,293 | |||||||||||||
Regulatory assets | $ | 150,972 | $ | 77,572 | ||||||||||||
Components of net periodic benefit cost | Components of net periodic pension cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 10,123 | $ | 11,067 | $ | 9,416 | ||||||||||
Interest cost | 20,093 | 18,062 | 18,019 | |||||||||||||
Expected return on plan assets | (28,742 | ) | (26,849 | ) | (24,121 | ) | ||||||||||
Recognized net (gain) loss | 4,937 | 9,461 | 4,100 | |||||||||||||
Net amortization | 1,088 | 1,143 | 1,309 | |||||||||||||
Net periodic pension cost | $ | 7,499 | $ | 12,884 | $ | 8,723 | ||||||||||
Fair values of benefit plan assets | The fair values of pension plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 78,344 | $ | 32,366 | $ | — | $ | 110,710 | ||||||||
International equity* | 49,170 | 45,313 | — | 94,483 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 32,145 | — | 32,145 | ||||||||||||
Mortgage- and asset-backed securities | — | 8,646 | — | 8,646 | ||||||||||||
Corporate bonds | — | 52,185 | — | 52,185 | ||||||||||||
Pooled funds | — | 23,632 | — | 23,632 | ||||||||||||
Cash equivalents and other | 133 | 30,327 | — | 30,460 | ||||||||||||
Real estate investments | 13,479 | — | 51,520 | 64,999 | ||||||||||||
Private equity | — | — | 26,203 | 26,203 | ||||||||||||
Total | $ | 141,126 | $ | 224,614 | $ | 77,723 | $ | 443,463 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (89 | ) | $ | — | $ | — | $ | (89 | ) | ||||||
Total | $ | 141,037 | $ | 224,614 | $ | 77,723 | $ | 443,374 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 63,558 | $ | 37,206 | $ | — | $ | 100,764 | ||||||||
International equity* | 48,829 | 45,146 | — | 93,975 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 26,582 | — | 26,582 | ||||||||||||
Mortgage- and asset-backed securities | — | 6,904 | — | 6,904 | ||||||||||||
Corporate bonds | — | 43,420 | — | 43,420 | ||||||||||||
Pooled funds | — | 20,905 | — | 20,905 | ||||||||||||
Cash equivalents and other | 38 | 9,896 | — | 9,934 | ||||||||||||
Real estate investments | 11,546 | — | 44,341 | 55,887 | ||||||||||||
Private equity | — | — | 25,316 | 25,316 | ||||||||||||
Total | $ | 123,971 | $ | 190,059 | $ | 69,657 | $ | 383,687 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (115 | ) | $ | — | $ | (115 | ) | ||||||
Total | $ | 123,971 | $ | 189,944 | $ | 69,657 | $ | 383,572 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the pension plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate | Private Equity | Real Estate | Private Equity | |||||||||||||
Investments | Investments | |||||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 44,341 | $ | 25,316 | $ | 37,196 | $ | 26,240 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 5,253 | 3,269 | 3,385 | 378 | ||||||||||||
Related to investments sold during the year | 1,525 | (745 | ) | 1,316 | 2,300 | |||||||||||
Total return on investments | 6,778 | 2,524 | 4,701 | 2,678 | ||||||||||||
Purchases, sales, and settlements | 401 | (1,637 | ) | 2,444 | (3,602 | ) | ||||||||||
Ending balance | $ | 51,520 | $ | 26,203 | $ | 44,341 | $ | 25,316 | ||||||||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||||||||||||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||||||||||||
Amounts related to defined benefit pension plans that had not yet been recognized in net periodic pension cost along with estimated amortization | Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2014 and 2013 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost along with the estimated amortization of such amounts for 2015. | |||||||||||||||
2014 | 2013 | Estimated Amortization in 2015 | ||||||||||||||
(in thousands) | ||||||||||||||||
Prior service cost | $ | (2,123 | ) | $ | (2,311 | ) | $ | (188 | ) | |||||||
Net (gain) loss | 18,457 | 4,427 | 778 | |||||||||||||
Net regulatory assets | $ | 16,334 | $ | 2,116 | ||||||||||||
Components of net periodic benefit cost | Components of the other postretirement benefit plans' net periodic cost were as follows: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(in thousands) | ||||||||||||||||
Service cost | $ | 1,025 | $ | 1,151 | $ | 1,038 | ||||||||||
Interest cost | 3,812 | 3,619 | 4,155 | |||||||||||||
Expected return on plan assets | (1,585 | ) | (1,472 | ) | (1,552 | ) | ||||||||||
Net amortization | (188 | ) | 471 | 470 | ||||||||||||
Net periodic postretirement benefit cost | $ | 3,064 | $ | 3,769 | $ | 4,111 | ||||||||||
Fair values of benefit plan assets | The fair values of other postretirement benefit plan assets as of December 31, 2014 and 2013 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Assets that are considered special situations investments, primarily real estate investments and private equities, are presented in the tables below based on the nature of the investment. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 3,450 | $ | 1,425 | $ | — | $ | 4,875 | ||||||||
International equity* | 2,165 | 1,997 | — | 4,162 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 5,279 | — | 5,279 | ||||||||||||
Mortgage- and asset-backed securities | — | 380 | — | 380 | ||||||||||||
Corporate bonds | — | 2,301 | — | 2,301 | ||||||||||||
Pooled funds | — | 1,041 | — | 1,041 | ||||||||||||
Cash equivalents and other | 589 | 1,337 | — | 1,926 | ||||||||||||
Real estate investments | 593 | — | 2,269 | 2,862 | ||||||||||||
Private equity | — | — | 1,154 | 1,154 | ||||||||||||
Total | $ | 6,797 | $ | 13,760 | $ | 3,423 | $ | 23,980 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | (5 | ) | $ | — | $ | — | $ | (5 | ) | ||||||
Total | $ | 6,792 | $ | 13,760 | $ | 3,423 | $ | 23,975 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Domestic equity* | $ | 3,089 | $ | 1,809 | $ | — | $ | 4,898 | ||||||||
International equity* | 2,375 | 2,193 | — | 4,568 | ||||||||||||
Fixed income: | ||||||||||||||||
U.S. Treasury, government, and agency bonds | — | 5,213 | — | 5,213 | ||||||||||||
Mortgage- and asset-backed securities | — | 337 | — | 337 | ||||||||||||
Corporate bonds | — | 2,109 | — | 2,109 | ||||||||||||
Pooled funds | — | 1,016 | — | 1,016 | ||||||||||||
Cash equivalents and other | 1 | 968 | — | 969 | ||||||||||||
Real estate investments | 560 | — | 2,156 | 2,716 | ||||||||||||
Private equity | — | — | 1,231 | 1,231 | ||||||||||||
Total | $ | 6,025 | $ | 13,645 | $ | 3,387 | $ | 23,057 | ||||||||
Liabilities: | ||||||||||||||||
Derivatives | $ | — | $ | (5 | ) | $ | — | $ | (5 | ) | ||||||
Total | $ | 6,025 | $ | 13,640 | $ | 3,387 | $ | 23,052 | ||||||||
* | Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | |||||||||||||||
Changes in fair value measurement of the level 3 items in benefit plan assets | Changes in the fair value measurement of the Level 3 items in the other postretirement benefit plan assets valued using significant unobservable inputs for the years ended December 31, 2014 and 2013 were as follows: | |||||||||||||||
2014 | 2013 | |||||||||||||||
Real Estate Investments | Private Equity | Real Estate Investments | Private Equity | |||||||||||||
(in thousands) | ||||||||||||||||
Beginning balance | $ | 2,156 | $ | 1,231 | $ | 1,865 | $ | 1,293 | ||||||||
Actual return on investments: | ||||||||||||||||
Related to investments held at year end | 28 | 28 | 158 | 18 | ||||||||||||
Related to investments sold during the year | 67 | (33 | ) | 64 | 110 | |||||||||||
Total return on investments | 95 | (5 | ) | 222 | 128 | |||||||||||
Purchases, sales, and settlements | 18 | (72 | ) | 69 | (190 | ) | ||||||||||
Ending balance | $ | 2,269 | $ | 1,154 | $ | 2,156 | $ | 1,231 | ||||||||
Contingencies_and_Regulatory_M1
Contingencies and Regulatory Matters (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Current cost estimate and actual costs incurred | Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision), and actual costs incurred as of December 31, 2014, as adjusted for the Court's decision, are as follows: | |||||||||||
Cost Category | 2010 | Current Estimate | Actual Costs at 12/31/2014 | |||||||||
Project Estimate(f) | ||||||||||||
(in billions) | ||||||||||||
Plant Subject to Cost Cap(a) | $ | 2.4 | $ | 4.93 | $ | 4.23 | ||||||
Lignite Mine and Equipment | 0.21 | 0.23 | 0.23 | |||||||||
CO2 Pipeline Facilities | 0.14 | 0.11 | 0.1 | |||||||||
AFUDC(b)(c) | 0.17 | 0.63 | 0.45 | |||||||||
Combined Cycle and Related Assets Placed in | — | 0.02 | 0 | |||||||||
Service – Incremental(d) | ||||||||||||
General Exceptions | 0.05 | 0.1 | 0.07 | |||||||||
Deferred Costs(c)(e) | — | 0.18 | 0.12 | |||||||||
Total Kemper IGCC(a)(c) | $ | 2.97 | $ | 6.2 | $ | 5.2 | ||||||
(a) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014 that are subject to the $2.88 billion cost cap and excludes post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(b) | Mississippi Power's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." | |||||||||||
(c) | Amounts in the Current Estimate reflect estimated costs through March 31, 2016. | |||||||||||
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||
(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC. | |||||||||||
Mississippi Power [Member] | ||||||||||||
Loss Contingencies [Line Items] | ||||||||||||
Current cost estimate and actual costs incurred | The Company's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court's decision), and actual costs incurred as of December 31, 2014, as adjusted for the Court's decision, are as follows: | |||||||||||
Cost Category | 2010 Project Estimate(f) | Current Estimate | Actual Costs at 12/31/2014 | |||||||||
(in billions) | ||||||||||||
Plant Subject to Cost Cap(a) | $ | 2.4 | $ | 4.93 | $ | 4.23 | ||||||
Lignite Mine and Equipment | 0.21 | 0.23 | 0.23 | |||||||||
CO2 Pipeline Facilities | 0.14 | 0.11 | 0.1 | |||||||||
AFUDC(b)(c) | 0.17 | 0.63 | 0.45 | |||||||||
Combined Cycle and Related Assets Placed in | — | 0.02 | 0 | |||||||||
Service – Incremental(d) | ||||||||||||
General Exceptions | 0.05 | 0.1 | 0.07 | |||||||||
Deferred Costs(c)(e) | — | 0.18 | 0.12 | |||||||||
Total Kemper IGCC(a)(c) | $ | 2.97 | $ | 6.2 | $ | 5.2 | ||||||
(a) | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014 that are subject to the $2.88 billion cost cap and excludes post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(b) | The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." | |||||||||||
(c) | Amounts in the Current Estimate reflect estimated costs through March 31, 2016. | |||||||||||
(d) | Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014, net of costs related to energy sales. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" for additional information. | |||||||||||
(e) | The 2012 MPSC CPCN Order approved deferral of non-capital Kemper IGCC-related costs during construction as described in "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities." | |||||||||||
(f) | The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities which was approved in 2011 by the Mississippi PSC. | |||||||||||
Of the total costs, including post-in-service costs for the lignite mine, incurred as of |
Joint_Ownership_Agreements_Tab
Joint Ownership Agreements (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||||||||||
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2014, Alabama Power's, Georgia Power's, and Southern Power's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows: | ||||||||||||||||||
Facility (Type) | Percent | Plant in Service | Accumulated | CWIP | |||||||||||||||
Ownership | Depreciation | ||||||||||||||||||
(in millions) | |||||||||||||||||||
Plant Vogtle (nuclear) Units 1 and 2 | 45.7 | % | $ | 3,420 | $ | 2,059 | $ | 46 | |||||||||||
Plant Hatch (nuclear) | 50.1 | 1,117 | 559 | 66 | |||||||||||||||
Plant Miller (coal) Units 1 and 2 | 91.8 | 1,512 | 561 | 14 | |||||||||||||||
Plant Scherer (coal) Units 1 and 2 | 8.4 | 254 | 83 | 1 | |||||||||||||||
Plant Wansley (coal) | 53.5 | 856 | 278 | 15 | |||||||||||||||
Rocky Mountain (pumped storage) | 25.4 | 182 | 124 | 2 | |||||||||||||||
Intercession City (combustion turbine) | 33.3 | 14 | 5 | — | |||||||||||||||
Plant Stanton (combined cycle) Unit A | 65 | 157 | 47 | — | |||||||||||||||
Alabama Power [Member] | |||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||||||||||
Schedule of percentage ownership and investment in jointly-owned facilities | In addition to the Company's ownership of SEGCO and joint ownership of the natural gas pipeline, the Company's percentage ownership and investment in jointly-owned coal-fired generating plants at December 31, 2014 were as follows: | ||||||||||||||||||
Facility | Total MW Capacity | Company Ownership | Plant in Service | Accumulated Depreciation | Construction Work in Progress | ||||||||||||||
(in millions) | |||||||||||||||||||
Greene County | 500 | 60 | % | (1) | $ | 164 | $ | 96 | $ | 1 | |||||||||
Plant Miller | |||||||||||||||||||
Units 1 and 2 | 1,320 | 91.84 | % | (2) | 1,512 | 561 | 14 | ||||||||||||
-1 | Jointly owned with an affiliate, Mississippi Power. | ||||||||||||||||||
-2 | Jointly owned with PowerSouth Energy Cooperative, Inc. | ||||||||||||||||||
Georgia Power [Member] | |||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||||||||||
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2014, the Company's percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation with the above entities were as follows: | ||||||||||||||||||
Facility (Type) | Company Ownership | Plant in Service | Accumulated Depreciation | CWIP | |||||||||||||||
(in millions) | |||||||||||||||||||
Plant Vogtle (nuclear) | |||||||||||||||||||
Units 1 and 2 | 45.70% | $ | 3,420 | $ | 2,059 | $ | 46 | ||||||||||||
Plant Hatch (nuclear) | 50.1 | 1,117 | 559 | 66 | |||||||||||||||
Plant Wansley (coal) | 53.5 | 856 | 278 | 15 | |||||||||||||||
Plant Scherer (coal) | |||||||||||||||||||
Units 1 and 2 | 8.4 | 254 | 83 | 1 | |||||||||||||||
Unit 3 | 75 | 1,172 | 417 | 10 | |||||||||||||||
Rocky Mountain (pumped storage) | 25.4 | 182 | 124 | 2 | |||||||||||||||
Intercession City (combustion-turbine) | 33.3 | 14 | 5 | — | |||||||||||||||
Gulf Power [Member] | |||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||||||||||
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2014, the Company's percentage ownership and investment in these jointly-owned facilities were as follows: | ||||||||||||||||||
Plant Scherer | Plant Daniel Units 1 & 2 (coal) | ||||||||||||||||||
Unit 3 (coal) | |||||||||||||||||||
(in thousands) | |||||||||||||||||||
Plant in service | $ | 387,511 | (a) | $ | 285,834 | ||||||||||||||
Accumulated depreciation | 130,069 | 177,304 | |||||||||||||||||
Construction work in progress | 2,912 | 286,343 | |||||||||||||||||
Company Ownership | 25 | % | 50 | % | |||||||||||||||
(a) | Includes net plant acquisition adjustment of $1.8 million. | ||||||||||||||||||
Mississippi Power [Member] | |||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | |||||||||||||||||||
Schedule of percentage ownership and investment in jointly-owned facilities | At December 31, 2014, the Company's percentage ownership and investment in these jointly-owned facilities in commercial operation were as follows: | ||||||||||||||||||
Generating | Company | Plant in Service | Accumulated | CWIP | |||||||||||||||
Plant | Ownership | Depreciation | |||||||||||||||||
(in thousands) | |||||||||||||||||||
Greene County | |||||||||||||||||||
Units 1 and 2 | 40 | % | $ | 102,384 | $ | 51,911 | $ | 902 | |||||||||||
Daniel | |||||||||||||||||||
Units 1 and 2 | 50 | % | $ | 299,440 | $ | 155,606 | $ | 286,240 | |||||||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
Details of income tax provisions | Details of income tax provisions are as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal — | ||||||||||||
Current | $ | 175 | $ | 363 | $ | 177 | ||||||
Deferred | 695 | 386 | 1,011 | |||||||||
870 | 749 | 1,188 | ||||||||||
State — | ||||||||||||
Current | 93 | (10 | ) | 61 | ||||||||
Deferred | 14 | 110 | 85 | |||||||||
107 | 100 | 146 | ||||||||||
Total | $ | 977 | $ | 849 | $ | 1,334 | ||||||
Tax effects between the carrying amounts of assets and liabilities | The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | |||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation | $ | 11,125 | $ | 9,710 | ||||||||
Property basis differences | 1,332 | 1,515 | ||||||||||
Leveraged lease basis differences | 299 | 287 | ||||||||||
Employee benefit obligations | 613 | 491 | ||||||||||
Premium on reacquired debt | 103 | 113 | ||||||||||
Regulatory assets associated with employee benefit obligations | 1,390 | 705 | ||||||||||
Regulatory assets associated with AROs | 871 | 824 | ||||||||||
Other | 523 | 350 | ||||||||||
Total | 16,256 | 13,995 | ||||||||||
Deferred tax assets — | ||||||||||||
Federal effect of state deferred taxes | 430 | 421 | ||||||||||
Employee benefit obligations | 1,675 | 1,048 | ||||||||||
Over recovered fuel clause | — | 30 | ||||||||||
Other property basis differences | 453 | 157 | ||||||||||
Deferred costs | 86 | 84 | ||||||||||
ITC carryforward | 480 | 121 | ||||||||||
Unbilled revenue | 67 | 116 | ||||||||||
Other comprehensive losses | 89 | 54 | ||||||||||
AROs | 871 | 824 | ||||||||||
Estimated Loss on Kemper IGCC | 631 | 472 | ||||||||||
Deferred state tax assets | 117 | 77 | ||||||||||
Other | 342 | 220 | ||||||||||
Total | 5,241 | 3,624 | ||||||||||
Valuation allowance | (49 | ) | (49 | ) | ||||||||
Total deferred tax assets | 5,192 | 3,575 | ||||||||||
Total deferred tax liabilities, net | 11,064 | 10,420 | ||||||||||
Portion included in current assets/(liabilities), net | 504 | 143 | ||||||||||
Accumulated deferred income taxes | $ | 11,568 | $ | 10,563 | ||||||||
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | ||||||
State income tax, net of federal deduction | 2.3 | 2.5 | 2.5 | |||||||||
Employee stock plans dividend deduction | (1.4 | ) | (1.6 | ) | (1.0 | ) | ||||||
Non-deductible book depreciation | 1.4 | 1.5 | 0.9 | |||||||||
AFUDC-Equity | (2.9 | ) | (2.6 | ) | (1.3 | ) | ||||||
ITC basis difference | (1.6 | ) | (1.2 | ) | (0.3 | ) | ||||||
Other | (0.3 | ) | (0.5 | ) | (0.2 | ) | ||||||
Effective income tax rate | 32.5 | % | 33.1 | % | 35.6 | % | ||||||
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 7 | $ | 70 | $ | 120 | ||||||
Tax positions increase from current periods | 64 | 3 | 13 | |||||||||
Tax positions increase from prior periods | 102 | — | 7 | |||||||||
Tax positions decrease from prior periods | (3 | ) | (66 | ) | (56 | ) | ||||||
Reductions due to settlements | — | — | (10 | ) | ||||||||
Reductions due to expired statute of limitations | — | — | (4 | ) | ||||||||
Balance at end of year | $ | 170 | $ | 7 | $ | 70 | ||||||
Impact on effective tax rate | The impact on Southern Company's effective tax rate, if recognized, is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Tax positions impacting the effective tax rate | $ | 10 | $ | 7 | $ | 5 | ||||||
Tax positions not impacting the effective tax rate | 160 | — | 65 | |||||||||
Balance of unrecognized tax benefits | $ | 170 | $ | 7 | $ | 70 | ||||||
Alabama Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
Details of income tax provisions | Details of income tax provisions are as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal — | ||||||||||||
Current | $ | 198 | $ | 243 | $ | 262 | ||||||
Deferred | 225 | 160 | 137 | |||||||||
423 | 403 | 399 | ||||||||||
State — | ||||||||||||
Current | 44 | 36 | 51 | |||||||||
Deferred | 45 | 39 | 27 | |||||||||
89 | 75 | 78 | ||||||||||
Total | $ | 512 | $ | 478 | $ | 477 | ||||||
Tax effects between the carrying amounts of assets and liabilities | The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | |||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation | $ | 3,429 | $ | 3,187 | ||||||||
Property basis differences | 457 | 458 | ||||||||||
Premium on reacquired debt | 30 | 33 | ||||||||||
Employee benefit obligations | 215 | 209 | ||||||||||
Regulatory assets associated with employee benefit obligations | 366 | 198 | ||||||||||
Asset retirement obligations | 59 | 38 | ||||||||||
Regulatory assets associated with asset retirement obligations | 285 | 265 | ||||||||||
Other | 156 | 128 | ||||||||||
Total | 4,997 | 4,516 | ||||||||||
Deferred tax assets — | ||||||||||||
Federal effect of state deferred taxes | 219 | 205 | ||||||||||
Unbilled fuel revenue | 42 | 41 | ||||||||||
Storm reserve | 27 | 32 | ||||||||||
Employee benefit obligations | 400 | 231 | ||||||||||
Other comprehensive losses | 19 | 18 | ||||||||||
Asset retirement obligations | 344 | 303 | ||||||||||
Other | 90 | 108 | ||||||||||
Total | 1,141 | 938 | ||||||||||
Total deferred tax liabilities, net | 3,856 | 3,578 | ||||||||||
Portion included in current assets/(liabilities), net | 18 | 25 | ||||||||||
Accumulated deferred income taxes | $ | 3,874 | $ | 3,603 | ||||||||
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |||||||||
State income tax, net of federal deduction | 4.4 | 4 | 4.1 | |||||||||
Non-deductible book depreciation | 1.1 | 1 | 0.9 | |||||||||
Differences in prior years' deferred and current tax rates | -0.1 | -0.1 | -0.1 | |||||||||
AFUDC equity | -1.3 | -0.9 | -0.5 | |||||||||
Other | -0.1 | -0.1 | -0.3 | |||||||||
Effective income tax rate | 39.00% | 38.90% | 39.10% | |||||||||
Changes in unrecognized tax benefits | The Company had no unrecognized tax benefits during 2014. Changes in unrecognized tax benefits in prior years were as follows: | |||||||||||
2013 | 2012 | |||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 31 | $ | 32 | ||||||||
Tax positions from current periods | — | 5 | ||||||||||
Tax positions from prior periods | (31 | ) | (4 | ) | ||||||||
Reductions due to settlements | — | (2 | ) | |||||||||
Balance at end of year | $ | — | $ | 31 | ||||||||
Georgia Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
Details of income tax provisions | Details of income tax provisions are as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal – | ||||||||||||
Current | $ | 295 | $ | 277 | $ | 273 | ||||||
Deferred | 366 | 374 | 370 | |||||||||
661 | 651 | 643 | ||||||||||
State – | ||||||||||||
Current | 82 | (30 | ) | 38 | ||||||||
Deferred | (14 | ) | 102 | 7 | ||||||||
68 | 72 | 45 | ||||||||||
Total | $ | 729 | $ | 723 | $ | 688 | ||||||
Tax effects between the carrying amounts of assets and liabilities | The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | |||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities – | ||||||||||||
Accelerated depreciation | $ | 4,732 | $ | 4,479 | ||||||||
Property basis differences | 811 | 873 | ||||||||||
Employee benefit obligations | 329 | 232 | ||||||||||
Under-recovered fuel costs | 81 | — | ||||||||||
Premium on reacquired debt | 66 | 73 | ||||||||||
Regulatory assets associated with employee benefit obligations | 534 | 276 | ||||||||||
Asset retirement obligations | 497 | 495 | ||||||||||
Other | 160 | 168 | ||||||||||
Total | 7,210 | 6,596 | ||||||||||
Deferred tax assets – | ||||||||||||
Federal effect of state deferred taxes | 148 | 159 | ||||||||||
Employee benefit obligations | 642 | 388 | ||||||||||
Other property basis differences | 86 | 93 | ||||||||||
Other deferred costs | 86 | 84 | ||||||||||
Cost of removal obligations | 11 | 17 | ||||||||||
State tax credit carry forward | 170 | 118 | ||||||||||
Federal tax credit carry forward | 5 | 3 | ||||||||||
Over-recovered fuel costs | — | 22 | ||||||||||
Unbilled fuel revenue | 46 | 53 | ||||||||||
Asset retirement obligations | 497 | 495 | ||||||||||
Other | 46 | 32 | ||||||||||
Total | 1,737 | 1,464 | ||||||||||
Total deferred tax liabilities, net | 5,473 | 5,132 | ||||||||||
Portion included in current assets/(liabilities), net | 34 | 68 | ||||||||||
Accumulated deferred income taxes | $ | 5,507 | $ | 5,200 | ||||||||
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |||||||||
State income tax, net of federal deduction | 2.2 | 2.5 | 1.6 | |||||||||
Non-deductible book depreciation | 1.3 | 1.3 | 1.2 | |||||||||
AFUDC equity | -0.8 | -0.6 | -1 | |||||||||
Other | -0.7 | -0.4 | -0.1 | |||||||||
Effective income tax rate | 37.00% | 37.80% | 36.70% | |||||||||
Changes in unrecognized tax benefits | Changes in unrecognized tax benefits in prior years were as follows: | |||||||||||
2013 | 2012 | |||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 23 | $ | 47 | ||||||||
Tax positions increase from current periods | — | 3 | ||||||||||
Tax positions increase from prior periods | — | 3 | ||||||||||
Tax positions decrease from prior periods | (23 | ) | (19 | ) | ||||||||
Reductions due to settlements | — | (8 | ) | |||||||||
Reductions due to expired statute of limitations | — | (3 | ) | |||||||||
Balance at end of year | $ | — | $ | 23 | ||||||||
Gulf Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
Details of income tax provisions | Details of income tax provisions are as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Federal - | ||||||||||||
Current | $ | 22,771 | $ | 5,009 | $ | (92,610 | ) | |||||
Deferred | 52,602 | 63,134 | 161,096 | |||||||||
75,373 | 68,143 | 68,486 | ||||||||||
State - | ||||||||||||
Current | (39 | ) | (2,410 | ) | (2,484 | ) | ||||||
Deferred | 12,728 | 13,935 | 13,209 | |||||||||
12,689 | 11,525 | 10,725 | ||||||||||
Total | $ | 88,062 | $ | 79,668 | $ | 79,211 | ||||||
Tax effects between the carrying amounts of assets and liabilities | The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | |||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax liabilities- | ||||||||||||
Accelerated depreciation | $ | 776,953 | $ | 721,087 | ||||||||
Property basis differences | 52,242 | 45,960 | ||||||||||
Fuel recovery clause | 16,148 | 7,972 | ||||||||||
Pension and other employee benefits | 34,405 | 25,800 | ||||||||||
Regulatory assets associated with employee benefit obligations | 59,788 | 27,660 | ||||||||||
Regulatory assets associated with asset retirement obligations | 6,768 | 6,554 | ||||||||||
Other | 21,712 | 23,947 | ||||||||||
Total | 968,016 | 858,980 | ||||||||||
Deferred tax assets- | ||||||||||||
Federal effect of state deferred taxes | 30,587 | 24,277 | ||||||||||
Postretirement benefits | 18,033 | 17,816 | ||||||||||
Pension and other employee benefits | 65,506 | 33,015 | ||||||||||
Property reserve | 13,440 | 15,144 | ||||||||||
Asset retirement obligations | 6,768 | 6,554 | ||||||||||
Alternative minimum tax carryforward | 18,200 | 18,420 | ||||||||||
Other | 18,893 | 17,780 | ||||||||||
Total | 171,427 | 133,006 | ||||||||||
Net deferred tax liabilities | 796,589 | 725,974 | ||||||||||
Portion included in current assets/(liabilities), net | 3,134 | 8,381 | ||||||||||
Accumulated deferred income taxes | $ | 799,723 | $ | 734,355 | ||||||||
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |||||||||
State income tax, net of federal deduction | 3.5 | 3.5 | 3.3 | |||||||||
Non-deductible book depreciation | 0.4 | 0.5 | 0.5 | |||||||||
Differences in prior years' deferred and current tax rates | -0.1 | -0.2 | -0.2 | |||||||||
AFUDC equity | -1.8 | -1.1 | -0.9 | |||||||||
Other, net | 0.1 | -0.1 | -0.2 | |||||||||
Effective income tax rate | 37.10% | 37.60% | 37.50% | |||||||||
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 45 | $ | 5,007 | $ | 2,892 | ||||||
Tax positions increase from current periods | 46 | 45 | 2,630 | |||||||||
Tax positions increase/(decrease) from prior periods | (45 | ) | (5,007 | ) | 515 | |||||||
Reductions due to settlements | — | — | (1,030 | ) | ||||||||
Balance at end of year | $ | 46 | $ | 45 | $ | 5,007 | ||||||
Impact on effective tax rate | The impact on the Company's effective tax rate, if recognized, is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Tax positions impacting the effective tax rate | $ | 46 | $ | 45 | $ | 45 | ||||||
Tax positions not impacting the effective tax rate | — | — | 4,962 | |||||||||
Balance of unrecognized tax benefits | $ | 46 | $ | 45 | $ | 5,007 | ||||||
Mississippi Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
Details of income tax provisions | Details of income tax provisions are as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Federal — | ||||||||||||
Current | $ | (431,077 | ) | $ | 23,345 | $ | 1,212 | |||||
Deferred | 183,461 | (342,870 | ) | 16,994 | ||||||||
(247,616 | ) | (319,525 | ) | 18,206 | ||||||||
State — | ||||||||||||
Current | 455 | 5,219 | 1,656 | |||||||||
Deferred | (38,044 | ) | (53,529 | ) | 694 | |||||||
(37,589 | ) | (48,310 | ) | 2,350 | ||||||||
Total | $ | (285,205 | ) | $ | (367,835 | ) | $ | 20,556 | ||||
Tax effects between the carrying amounts of assets and liabilities | The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | |||||||||||
2014 | 2013 | |||||||||||
(in thousands) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation | $ | 1,068,242 | $ | 371,553 | ||||||||
Property basis differences | — | 130,679 | ||||||||||
ECM under recovered | — | 1,777 | ||||||||||
Regulatory assets associated with AROs | 19,299 | 16,764 | ||||||||||
Pensions and other benefits | 35,200 | 23,769 | ||||||||||
Regulatory assets associated with employee benefit obligations | 67,727 | 33,127 | ||||||||||
Regulatory assets associated with the Kemper IGCC | 61,561 | 30,708 | ||||||||||
Rate differential | 89,040 | 56,074 | ||||||||||
Federal effect of state deferred taxes | 1,279 | 30,615 | ||||||||||
Fuel clause under recovered | 3,288 | — | ||||||||||
Other | 52,215 | 35,583 | ||||||||||
Total | 1,397,851 | 730,649 | ||||||||||
Deferred tax assets — | ||||||||||||
Fuel clause over recovered | — | 7,741 | ||||||||||
Estimated loss on Kemper IGCC | 631,326 | 472,000 | ||||||||||
Pension and other benefits | 92,232 | 57,999 | ||||||||||
Property insurance | 24,315 | 23,693 | ||||||||||
Premium on long-term debt | 20,694 | 23,736 | ||||||||||
Unbilled fuel | 14,535 | 12,136 | ||||||||||
AROs | 19,299 | 16,764 | ||||||||||
Interest rate hedges | 4,544 | 5,094 | ||||||||||
Kemper rate factor - regulatory liability retail | 108,312 | 36,210 | ||||||||||
Property basis difference | 263,430 | — | ||||||||||
ECM over recovered | 905 | — | ||||||||||
Deferred state tax assets | 56,736 | — | ||||||||||
Other | 15,111 | 18,094 | ||||||||||
Total | 1,251,439 | 673,467 | ||||||||||
Total deferred tax liabilities, net | 146,412 | 57,182 | ||||||||||
Portion included in (accrued) prepaid income taxes, net | 121,049 | 15,626 | ||||||||||
Deferred state tax asset | 17,388 | — | ||||||||||
Accumulated deferred income taxes | $ | 284,849 | $ | 72,808 | ||||||||
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | (35.0 | )% | (35.0 | )% | 35 | % | ||||||
State income tax, net of federal deduction | (4.0 | ) | (3.7 | ) | 1.3 | |||||||
Non-deductible book depreciation | 0.1 | 0.1 | 0.3 | |||||||||
AFUDC-equity | (7.8 | ) | (5.0 | ) | (18.6 | ) | ||||||
Other | 0.1 | (0.1 | ) | (1.2 | ) | |||||||
Effective income tax rate (benefit rate) | (46.6 | )% | (43.7 | )% | 16.8 | % | ||||||
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 3,840 | $ | 5,755 | $ | 4,964 | ||||||
Tax positions from current periods | 58,148 | 226 | 1,186 | |||||||||
Tax positions from prior periods | 102,833 | (2,141 | ) | (26 | ) | |||||||
Settlements with taxing authorities | — | — | (369 | ) | ||||||||
Balance at end of year | $ | 164,821 | $ | 3,840 | $ | 5,755 | ||||||
Impact on effective tax rate | The impact on the Company's effective tax rate, if recognized, is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Tax positions impacting the effective tax rate | $ | 4,341 | $ | 3,840 | $ | 3,656 | ||||||
Tax positions not impacting the effective tax rate | 160,480 | — | 2,099 | |||||||||
Balance of unrecognized tax benefits | $ | 164,821 | $ | 3,840 | $ | 5,755 | ||||||
Accrued interest for unrecognized tax benefits | Accrued interest for unrecognized tax benefits was as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in thousands) | ||||||||||||
Interest accrued at beginning of year | $ | 1,171 | $ | 772 | $ | 680 | ||||||
Interest accrued during the year | 1,698 | 399 | 92 | |||||||||
Balance at end of year | $ | 2,869 | $ | 1,171 | $ | 772 | ||||||
Southern Power [Member] | ||||||||||||
Income Tax Disclosure [Line Items] | ||||||||||||
Details of income tax provisions | Details of income tax provisions are as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Federal — | ||||||||||||
Current | $ | 178.6 | $ | (120.2 | ) | $ | (133.1 | ) | ||||
Deferred | (166.0 | ) | 158.7 | 210.4 | ||||||||
12.6 | 38.5 | 77.3 | ||||||||||
State — | ||||||||||||
Current | (13.8 | ) | (5.2 | ) | (3.0 | ) | ||||||
Deferred | (2.0 | ) | 12.6 | 18.3 | ||||||||
(15.8 | ) | 7.4 | 15.3 | |||||||||
Total | $ | (3.2 | ) | $ | 45.9 | $ | 92.6 | |||||
Tax effects between the carrying amounts of assets and liabilities | The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows: | |||||||||||
2014 | 2013 | |||||||||||
(in millions) | ||||||||||||
Deferred tax liabilities — | ||||||||||||
Accelerated depreciation and other property basis differences | $ | 1,006.50 | $ | 829.5 | ||||||||
Basis difference on asset transfers | 2.6 | 2.8 | ||||||||||
Levelized capacity revenues | 17.1 | 11.2 | ||||||||||
Other | 5.7 | 0.9 | ||||||||||
Total | 1,031.90 | 844.4 | ||||||||||
Deferred tax assets — | ||||||||||||
Federal effect of state deferred taxes | 28.9 | 29.7 | ||||||||||
Net basis difference on federal ITCs | 101.5 | 58 | ||||||||||
Alternative minimum tax carryforward | 15 | 1.1 | ||||||||||
Unrealized tax credits | 305.2 | — | ||||||||||
Unrealized loss on interest rate swaps | 6.1 | 11.2 | ||||||||||
Levelized capacity revenues | 4.9 | 6 | ||||||||||
Deferred state tax assets | 14.5 | 17 | ||||||||||
Other | 4.1 | 4.7 | ||||||||||
Total | 480.2 | 127.7 | ||||||||||
Valuation Allowance | (7.5 | ) | (7.5 | ) | ||||||||
Net deferred income tax assets | 472.7 | 120.2 | ||||||||||
Total deferred tax liabilities, net | 559.2 | 724.2 | ||||||||||
Portion included in current assets/(liabilities), net | 303.6 | 0.2 | ||||||||||
Accumulated deferred income taxes | $ | 862.8 | $ | 724.4 | ||||||||
Reconciliation of federal statutory income tax rate to effective income tax rate | A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
Federal statutory rate | 35 | % | 35 | % | 35 | % | ||||||
State income tax, net of federal deduction | (6.0 | ) | 2.2 | 3.7 | ||||||||
Amortization of ITC | (4.3 | ) | (1.7 | ) | (1.0 | ) | ||||||
ITC basis difference | (27.7 | ) | (14.5 | ) | (2.6 | ) | ||||||
Other | 1.1 | 0.3 | (0.6 | ) | ||||||||
Effective income tax rate | (1.9 | )% | 21.3 | % | 34.5 | % | ||||||
Changes in unrecognized tax benefits | Changes during the year in unrecognized tax benefits were as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Unrecognized tax benefits at beginning of year | $ | 1.5 | $ | 2.9 | $ | 2.6 | ||||||
Tax positions increase from current periods | 4.7 | 1.6 | 0.7 | |||||||||
Tax positions decrease from prior periods | (1.5 | ) | (3.0 | ) | (0.2 | ) | ||||||
Reductions due to settlements | — | — | (0.2 | ) | ||||||||
Balance at end of year | $ | 4.7 | $ | 1.5 | $ | 2.9 | ||||||
Impact on effective tax rate | The impact on the Company's effective tax rate, if recognized, is as follows: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Tax positions impacting the effective tax rate | $4.70 | $1.50 | $0.30 | |||||||||
Tax positions not impacting the effective tax rate | — | — | 2.6 | |||||||||
Balance of unrecognized tax benefits | $4.70 | $1.50 | $2.90 |
Financing_Tables
Financing (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities and redemptions of securities due within one year at December 31 was as follows: | |||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
Senior notes | $ | 2,375 | $ | 428 | ||||||||||||||||||||||||||||||||||||
Other long-term debt | 775 | 12 | ||||||||||||||||||||||||||||||||||||||
Pollution control revenue bonds | 152 | — | ||||||||||||||||||||||||||||||||||||||
Capitalized leases | 31 | 29 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 3,333 | $ | 469 | ||||||||||||||||||||||||||||||||||||
Credit arrangements with banks | At December 31, 2014, committed credit arrangements with banks were as follows: | |||||||||||||||||||||||||||||||||||||||
Expires | Executable Term Loans | Due Within | ||||||||||||||||||||||||||||||||||||||
One Year | ||||||||||||||||||||||||||||||||||||||||
Company | 2015 | 2016 | 2017 | 2018 | Total | Unused | One | Two | Term Out | No Term Out | ||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | (in millions) | (in millions) | (in millions) | |||||||||||||||||||||||||||||||||||||
Southern Company | $ | — | $ | — | $ | — | $ | 1,000 | $ | 1,000 | $ | 1,000 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||
Alabama Power | 228 | 50 | — | 1,030 | 1,308 | 1,308 | 58 | — | 58 | 170 | ||||||||||||||||||||||||||||||
Georgia Power | — | 150 | — | 1,600 | 1,750 | 1,736 | — | — | — | — | ||||||||||||||||||||||||||||||
Gulf Power | 80 | 165 | 30 | — | 275 | 275 | 50 | — | 50 | 30 | ||||||||||||||||||||||||||||||
Mississippi Power | 135 | 165 | — | — | 300 | 300 | 25 | 40 | 65 | 70 | ||||||||||||||||||||||||||||||
Southern Power | — | — | — | 500 | 500 | 488 | — | — | — | — | ||||||||||||||||||||||||||||||
Other | 70 | — | — | — | 70 | 70 | 20 | — | 20 | 50 | ||||||||||||||||||||||||||||||
Total | $ | 513 | $ | 530 | $ | 30 | $ | 4,130 | $ | 5,203 | $ | 5,177 | $ | 153 | $ | 40 | $ | 193 | $ | 320 | ||||||||||||||||||||
Short-term borrowings | Details of short-term borrowings were as follows: | |||||||||||||||||||||||||||||||||||||||
Short-term Debt at the End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount | Weighted | |||||||||||||||||||||||||||||||||||||||
Outstanding | Average | |||||||||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||||||||||
Rate | ||||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 803 | 0.3 | % | ||||||||||||||||||||||||||||||||||||
Short-term bank debt | — | — | % | |||||||||||||||||||||||||||||||||||||
Total | $ | 803 | 0.3 | % | ||||||||||||||||||||||||||||||||||||
December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 1,082 | 0.2 | % | ||||||||||||||||||||||||||||||||||||
Short-term bank debt | 400 | 0.9 | % | |||||||||||||||||||||||||||||||||||||
Total | $ | 1,482 | 0.4 | % | ||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Credit arrangements with banks | At December 31, 2014, committed credit arrangements with banks were as follows: | |||||||||||||||||||||||||||||||||||||||
Expires(a) | Executable | Due Within One Year | ||||||||||||||||||||||||||||||||||||||
Term-Loans | ||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2018 | Total | Unused | One | Two | Term Out | No Term Out | ||||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$ | 228 | $ | 50 | $ | 1,030 | $ | 1,308 | $ | 1,308 | $ | 58 | $ | — | $ | 58 | $ | 170 | |||||||||||||||||||||||
(a) | No credit arrangements expire in 2017. | |||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities of long-term debt due within one year at December 31 was as follows: | |||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
Senior notes | $ | 1,050 | $ | — | ||||||||||||||||||||||||||||||||||||
Pollution control revenue bonds | 98 | — | ||||||||||||||||||||||||||||||||||||||
Capital lease | 6 | 5 | ||||||||||||||||||||||||||||||||||||||
Total | $ | 1,154 | $ | 5 | ||||||||||||||||||||||||||||||||||||
Credit arrangements with banks | At December 31, 2014, committed credit arrangements with banks were as follows: | |||||||||||||||||||||||||||||||||||||||
Expires(a) | ||||||||||||||||||||||||||||||||||||||||
2016 | 2018 | Total | Unused | |||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$150 | $1,600 | $1,750 | $1,736 | |||||||||||||||||||||||||||||||||||||
(a) | No credit arrangements expire in 2015 or 2017. | |||||||||||||||||||||||||||||||||||||||
Short-term borrowings | Details of short-term borrowings outstanding were as follows: | |||||||||||||||||||||||||||||||||||||||
Short-term Debt at the End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount | Weighted | |||||||||||||||||||||||||||||||||||||||
Outstanding | Average | |||||||||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||||||||||
Rate | ||||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 156 | 0.3 | % | ||||||||||||||||||||||||||||||||||||
December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Commercial paper | $ | 647 | 0.2 | % | ||||||||||||||||||||||||||||||||||||
Short-term bank debt | 400 | 0.9 | % | |||||||||||||||||||||||||||||||||||||
Total | $ | 1,047 | 0.5 | % | ||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Credit arrangements with banks | At December 31, 2014, committed credit arrangements with banks were as follows: | |||||||||||||||||||||||||||||||||||||||
Expires | Executable | Due Within One Year | ||||||||||||||||||||||||||||||||||||||
Term-Loans | ||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | 2017 | Total | Unused | One | Two | Term Out | No Term Out | ||||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$ | 80 | $ | 165 | $ | 30 | $ | 275 | $ | 275 | $ | 50 | $ | — | $ | 50 | $ | 30 | |||||||||||||||||||||||
Short-term borrowings | Details of short-term borrowings were as follows: | |||||||||||||||||||||||||||||||||||||||
Commercial Paper at the | ||||||||||||||||||||||||||||||||||||||||
End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount Outstanding | Weighted | |||||||||||||||||||||||||||||||||||||||
Average | ||||||||||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||||||||||
Rate | ||||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | $ | 110 | 0.30% | |||||||||||||||||||||||||||||||||||||
December 31, 2013 | $ | 136 | 0.20% | |||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Scheduled maturities and redemptions of securities due within one year | A summary of scheduled maturities and redemptions of securities due within one year at December 31, 2014 and 2013 was as follows: | |||||||||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
Bank term loans | $ | 775 | $ | — | ||||||||||||||||||||||||||||||||||||
Revenue bonds | — | 11.3 | ||||||||||||||||||||||||||||||||||||||
Capitalized leases | 2.7 | 2.5 | ||||||||||||||||||||||||||||||||||||||
Outstanding at December 31 | $ | 777.7 | $ | 13.8 | ||||||||||||||||||||||||||||||||||||
Credit arrangements with banks | At December 31, 2014, committed credit arrangements with banks were as follows: | |||||||||||||||||||||||||||||||||||||||
Expires | Executable | Due Within One Year | ||||||||||||||||||||||||||||||||||||||
Term-Loans | ||||||||||||||||||||||||||||||||||||||||
2015 | 2016 | Total | Unused | One | Two | Term Out | No Term Out | |||||||||||||||||||||||||||||||||
Year | Years | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
$135 | $165 | $300 | $300 | $25 | $40 | $65 | $70 | |||||||||||||||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Short-term borrowings | Details of short-term borrowings are shown below. The Company had no short-term borrowings in 2013. | |||||||||||||||||||||||||||||||||||||||
Commercial Paper at the | ||||||||||||||||||||||||||||||||||||||||
End of the Period | ||||||||||||||||||||||||||||||||||||||||
Amount Outstanding | Weighted Average Interest Rate | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||
December 31, 2014 | $ | 195 | 0.4 | % | ||||||||||||||||||||||||||||||||||||
Redeemable Preferred Stock [Member] | Alabama Power [Member] | ||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Line Items] | ||||||||||||||||||||||||||||||||||||||||
Redeemable preferred stock | Information for each outstanding series is in the table below: | |||||||||||||||||||||||||||||||||||||||
Preferred/Preference Stock | Par Value/Stated Capital Per Share | Shares Outstanding | Redemption Price Per Share | |||||||||||||||||||||||||||||||||||||
4.92% Preferred Stock | $100 | 80,000 | $103.23 | |||||||||||||||||||||||||||||||||||||
4.72% Preferred Stock | $100 | 50,000 | $102.18 | |||||||||||||||||||||||||||||||||||||
4.64% Preferred Stock | $100 | 60,000 | $103.14 | |||||||||||||||||||||||||||||||||||||
4.60% Preferred Stock | $100 | 100,000 | $104.20 | |||||||||||||||||||||||||||||||||||||
4.52% Preferred Stock | $100 | 50,000 | $102.93 | |||||||||||||||||||||||||||||||||||||
4.20% Preferred Stock | $100 | 135,115 | $105.00 | |||||||||||||||||||||||||||||||||||||
5.83% Class A Preferred Stock | $25 | 1,520,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
5.20% Class A Preferred Stock | $25 | 6,480,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
5.30% Class A Preferred Stock | $25 | 4,000,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
5.625% Preference Stock | $25 | 6,000,000 | Stated Capital | |||||||||||||||||||||||||||||||||||||
6.450% Preference Stock | $25 | 6,000,000 | * | |||||||||||||||||||||||||||||||||||||
6.500% Preference Stock | $25 | 2,000,000 | * | |||||||||||||||||||||||||||||||||||||
* | Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital |
Commitments_Tables
Commitments (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
Estimated minimum long-term purchase commitments | Estimated total obligations under these commitments at December 31, 2014 were as follows: | |||||||||||||||||||
Operating Leases (1) | Other | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 230 | $ | 11 | ||||||||||||||||
2016 | 234 | 11 | ||||||||||||||||||
2017 | 264 | 10 | ||||||||||||||||||
2018 | 270 | 7 | ||||||||||||||||||
2019 | 274 | 6 | ||||||||||||||||||
2020 and thereafter | 1,980 | 50 | ||||||||||||||||||
Total | $ | 3,252 | $ | 95 | ||||||||||||||||
-1 | A total of $1.1 billion of biomass PPAs included under operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. | |||||||||||||||||||
Estimated minimum lease payments under operating leases | As of December 31, 2014, estimated minimum lease payments under operating leases were as follows: | |||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Barges & | Other | Total | ||||||||||||||||||
Railcars | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 50 | $ | 50 | $ | 100 | ||||||||||||||
2016 | 41 | 48 | 89 | |||||||||||||||||
2017 | 18 | 47 | 65 | |||||||||||||||||
2018 | 9 | 35 | 44 | |||||||||||||||||
2019 | 6 | 23 | 29 | |||||||||||||||||
2020 and thereafter | 20 | 228 | 248 | |||||||||||||||||
Total | $ | 144 | $ | 431 | $ | 575 | ||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
Estimated minimum long-term purchase commitments | Total estimated minimum long-term obligations at December 31, 2014 were as follows: | |||||||||||||||||||
Operating | ||||||||||||||||||||
Lease | ||||||||||||||||||||
PPAs | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 37 | ||||||||||||||||||
2016 | 39 | |||||||||||||||||||
2017 | 40 | |||||||||||||||||||
2018 | 41 | |||||||||||||||||||
2019 | 43 | |||||||||||||||||||
2020 and thereafter | 137 | |||||||||||||||||||
Total commitments | $ | 337 | ||||||||||||||||||
Estimated minimum lease payments under operating leases | As of December 31, 2014, estimated minimum lease payments under operating leases were as follows: | |||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Railcars | Vehicles & Other | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 13 | $ | 3 | $ | 16 | ||||||||||||||
2016 | 11 | 3 | 14 | |||||||||||||||||
2017 | 7 | 3 | 10 | |||||||||||||||||
2018 | 5 | 1 | 6 | |||||||||||||||||
2019 | 5 | — | 5 | |||||||||||||||||
2020 and thereafter | 17 | — | 17 | |||||||||||||||||
Total | $ | 58 | $ | 10 | $ | 68 | ||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
Estimated long-term obligations | Estimated total long-term obligations at December 31, 2014 were as follows: | |||||||||||||||||||
Affiliate Capital Leases | Affiliate Operating Leases | Non-Affiliate | Vogtle | Total ($) | ||||||||||||||||
Operating | Units 1 and 2 | |||||||||||||||||||
Leases (4) | Capacity | |||||||||||||||||||
Payments | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 22 | $ | 90 | $ | 114 | $ | 11 | $ | 237 | ||||||||||
2016 | 22 | 100 | 117 | 11 | 250 | |||||||||||||||
2017 | 23 | 71 | 146 | 10 | 250 | |||||||||||||||
2018 | 23 | 62 | 150 | 7 | 242 | |||||||||||||||
2019 | 23 | 63 | 152 | 6 | 244 | |||||||||||||||
2020 and thereafter | 255 | 606 | 1,572 | 50 | 2,483 | |||||||||||||||
Total | $ | 368 | $ | 992 | $ | 2,251 | $ | 95 | $ | 3,706 | ||||||||||
Less: amounts representing executory costs(1) | 55 | |||||||||||||||||||
Net minimum lease payments | 313 | |||||||||||||||||||
Less: amounts representing interest(2) | 85 | |||||||||||||||||||
Present value of net minimum lease payments(3) | $ | 228 | ||||||||||||||||||
-1 | Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments. | |||||||||||||||||||
-2 | Amount necessary to reduce minimum lease payments to present value calculated at the Company's incremental borrowing rate at the inception of the leases. | |||||||||||||||||||
-3 | Once service commences under the PPAs beginning in 2015, the Company will recognize capital lease assets and capital lease obligations totaling $149 million, being the lesser of the estimated fair value of the lease property or the present value of the net minimum lease payments. | |||||||||||||||||||
-4 | A total of $1.1 billion of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. | |||||||||||||||||||
Estimated minimum lease payments under operating leases | As of December 31, 2014, estimated minimum lease payments under operating leases were as follows: | |||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Railcars | Other | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 18 | $ | 7 | $ | 25 | ||||||||||||||
2016 | 13 | 7 | 20 | |||||||||||||||||
2017 | 9 | 7 | 16 | |||||||||||||||||
2018 | 4 | 6 | 10 | |||||||||||||||||
2019 | 1 | 4 | 5 | |||||||||||||||||
2020 and thereafter | 3 | 11 | 14 | |||||||||||||||||
Total | $ | 48 | $ | 42 | $ | 90 | ||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||
Commitments [Line Items] | ||||||||||||||||||||
Estimated minimum long-term purchase commitments | Estimated total minimum long-term commitments at December 31, 2014 were as follows: | |||||||||||||||||||
Operating Lease PPAs | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 78.7 | ||||||||||||||||||
2016 | 78.7 | |||||||||||||||||||
2017 | 78.8 | |||||||||||||||||||
2018 | 78.9 | |||||||||||||||||||
2019 | 78.9 | |||||||||||||||||||
2020 and thereafter | 270.3 | |||||||||||||||||||
Total | $ | 664.3 | ||||||||||||||||||
Estimated minimum lease payments under operating leases | Estimated total minimum lease payments under these operating leases at December 31, 2014 were as follows: | |||||||||||||||||||
Minimum Lease Payments | ||||||||||||||||||||
Barges & | Other | Total | ||||||||||||||||||
Railcars | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
2015 | $ | 15.1 | $ | 0.1 | $ | 15.2 | ||||||||||||||
2016 | 15 | 0.1 | 15.1 | |||||||||||||||||
2017 | 1.4 | 0.1 | 1.5 | |||||||||||||||||
Total | $ | 31.5 | $ | 0.3 | $ | 31.8 | ||||||||||||||
Common_Stock_and_Stock_Compens1
Common Stock and Stock Compensation (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Equity [Abstract] | |||||||||
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted | The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted: | ||||||||
Year Ended December 31 | 2014 | 2013 | 2012 | ||||||
Expected volatility | 14.60% | 16.60% | 17.70% | ||||||
Expected term (in years) | 5 | 5 | 5 | ||||||
Interest rate | 1.50% | 0.90% | 0.90% | ||||||
Dividend yield | 4.90% | 4.40% | 4.20% | ||||||
Weighted average grant-date fair value | $2.20 | $2.93 | $3.39 | ||||||
Summary of stock option activity | Southern Company's activity in the stock option program for 2014 is summarized below: | ||||||||
Shares Subject to Option | Weighted Average Exercise Price | ||||||||
Outstanding at December 31, 2013 | 38,819,366 | $38.64 | |||||||
Granted | 12,812,691 | 41.4 | |||||||
Exercised | 11,585,363 | 35.06 | |||||||
Cancelled | 117,375 | 42.72 | |||||||
Outstanding at December 31, 2014 | 39,929,319 | $40.55 | |||||||
Exercisable at December 31, 2014 | 20,695,310 | $38.76 | |||||||
Assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted | The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of performance share award units granted: | ||||||||
Year Ended December 31 | 2014 | 2013 | 2012 | ||||||
Expected volatility | 12.60% | 12.00% | 16.00% | ||||||
Expected term (in years) | 3 | 3 | 3 | ||||||
Interest rate | 0.60% | 0.40% | 0.40% | ||||||
Annualized dividend rate | $2.03 | $1.96 | $1.89 | ||||||
Weighted average grant-date fair value | $37.54 | $40.50 | $41.99 | ||||||
Earnings per share | Shares used to compute diluted earnings per share were as follows: | ||||||||
Average Common Stock Shares | |||||||||
2014 | 2013 | 2012 | |||||||
(in millions) | |||||||||
As reported shares | 897 | 877 | 871 | ||||||
Effect of options and performance share award units | 4 | 4 | 8 | ||||||
Diluted shares | 901 | 881 | 879 | ||||||
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 13 | $ | — | $ | 13 | ||||||||
Interest rate derivatives | — | 8 | — | 8 | ||||||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 583 | 85 | — | 668 | ||||||||||||
Foreign equity | 34 | 184 | — | 218 | ||||||||||||
U.S. Treasury and government agency securities | — | 130 | — | 130 | ||||||||||||
Municipal bonds | — | 62 | — | 62 | ||||||||||||
Corporate bonds | — | 299 | — | 299 | ||||||||||||
Mortgage and asset backed securities | — | 139 | — | 139 | ||||||||||||
Other | 11 | 13 | 3 | 27 | ||||||||||||
Cash equivalents | 397 | — | — | 397 | ||||||||||||
Other investments | 9 | — | 1 | 10 | ||||||||||||
Total | $ | 1,034 | $ | 933 | $ | 4 | $ | 1,971 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 201 | $ | — | $ | 201 | ||||||||
Interest rate derivatives | — | 24 | — | 24 | ||||||||||||
Total | $ | — | $ | 225 | $ | — | $ | 225 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 24 | $ | — | $ | 24 | ||||||||
Interest rate derivatives | — | 3 | — | 3 | ||||||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 589 | 75 | — | 664 | ||||||||||||
Foreign equity | 35 | 196 | — | 231 | ||||||||||||
U.S. Treasury and government agency securities | — | 103 | — | 103 | ||||||||||||
Municipal bonds | — | 64 | — | 64 | ||||||||||||
Corporate bonds | — | 229 | — | 229 | ||||||||||||
Mortgage and asset backed securities | — | 132 | — | 132 | ||||||||||||
Other | — | 37 | 3 | 40 | ||||||||||||
Cash equivalents | 491 | — | — | 491 | ||||||||||||
Other investments | 9 | — | 4 | 13 | ||||||||||||
Total | $ | 1,124 | $ | 863 | $ | 7 | $ | 1,994 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 56 | $ | — | $ | 56 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | |||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity funds | $ | 121 | None | Monthly | 5 days | |||||||||||
Equity – commingled funds | 63 | None | Daily/Monthly | Daily/7 days | ||||||||||||
Debt – commingled funds | 15 | None | Daily | 5 days | ||||||||||||
Other – commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Other – money market funds | 11 | None | Daily | Not applicable | ||||||||||||
Trust-owned life insurance | 115 | None | Daily | 15 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 397 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity funds | $ | 131 | None | Monthly | 5 days | |||||||||||
Corporate bonds – commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Equity – commingled funds | 65 | None | Daily/Monthly | Daily/7 days | ||||||||||||
Other – commingled funds | 24 | None | Daily | Not applicable | ||||||||||||
Trust-owned life insurance | 110 | None | Daily | 15 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 491 | None | Daily | Not applicable | ||||||||||||
Financial instruments not having carrying amount equal to fair value | As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 24,015 | $ | 25,816 | ||||||||||||
2013 | $ | 21,650 | $ | 22,197 | ||||||||||||
Alabama Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 1 | $ | — | $ | 1 | ||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 403 | 83 | — | 486 | ||||||||||||
Foreign equity | 34 | 63 | — | 97 | ||||||||||||
U.S. Treasury and government agency securities | — | 34 | — | 34 | ||||||||||||
Corporate bonds | — | 111 | — | 111 | ||||||||||||
Mortgage and asset backed securities | — | 18 | — | 18 | ||||||||||||
Other | — | 5 | 3 | 8 | ||||||||||||
Cash equivalents | 162 | — | — | 162 | ||||||||||||
Total | $ | 599 | $ | 315 | $ | 3 | $ | 917 | ||||||||
Liabilities: | ||||||||||||||||
Interest rate derivatives | $ | — | $ | 8 | $ | — | $ | 8 | ||||||||
Energy-related derivatives | — | 53 | — | 53 | ||||||||||||
Total | $ | — | $ | 61 | $ | — | $ | 61 | ||||||||
(a) | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 7 | $ | — | $ | 7 | ||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 392 | 74 | — | 466 | ||||||||||||
Foreign equity | 35 | 65 | — | 100 | ||||||||||||
U.S. Treasury and government agency securities | — | 24 | — | 24 | ||||||||||||
Corporate bonds | — | 89 | — | 89 | ||||||||||||
Mortgage and asset backed securities | — | 18 | — | 18 | ||||||||||||
Other | — | 13 | 3 | 16 | ||||||||||||
Cash equivalents | 236 | — | — | 236 | ||||||||||||
Total | $ | 663 | $ | 290 | $ | 3 | $ | 956 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 8 | $ | — | $ | 8 | ||||||||
(a) | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. | |||||||||||||||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | |||||||||||||||
Fair | Unfunded | Redemption Frequency | Redemption | |||||||||||||
Value | Commitments | Notice Period | ||||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Equity – commingled funds | $ | 63 | None | Daily/Monthly | Daily/7 days | |||||||||||
Trust – owned life insurance | 115 | None | Daily | 15 days | ||||||||||||
Debt – commingled funds | 15 | None | Daily | 5 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 162 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Equity – commingled funds | $ | 65 | None | Daily/Monthly | Daily/7 days | |||||||||||
Trust – owned life insurance | 110 | None | Daily | 15 days | ||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | 236 | None | Daily | Not applicable | ||||||||||||
Financial instruments not having carrying amount equal to fair value | As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 6,631 | $ | 7,321 | ||||||||||||
2013 | $ | 6,228 | $ | 6,534 | ||||||||||||
Georgia Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 7 | $ | — | $ | 7 | ||||||||
Interest rate derivatives | — | 6 | — | 6 | ||||||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 180 | 2 | — | 182 | ||||||||||||
Foreign equity | — | 121 | — | 121 | ||||||||||||
U.S. Treasury and government agency securities | — | 96 | — | 96 | ||||||||||||
Municipal bonds | — | 62 | — | 62 | ||||||||||||
Corporate bonds | — | 188 | — | 188 | ||||||||||||
Mortgage and asset backed securities | — | 121 | — | 121 | ||||||||||||
Other | 11 | 8 | — | 19 | ||||||||||||
Total | $ | 191 | $ | 611 | $ | — | $ | 802 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 27 | $ | — | $ | 27 | ||||||||
Interest rate derivatives | — | 14 | — | 14 | ||||||||||||
Total | $ | — | $ | 41 | $ | — | $ | 41 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 5 | $ | — | $ | 5 | ||||||||
Nuclear decommissioning trusts:(a) | ||||||||||||||||
Domestic equity | 197 | 1 | — | 198 | ||||||||||||
Foreign equity | — | 131 | — | 131 | ||||||||||||
U.S. Treasury and government agency securities | — | 79 | — | 79 | ||||||||||||
Municipal bonds | — | 64 | — | 64 | ||||||||||||
Corporate bonds | — | 140 | — | 140 | ||||||||||||
Mortgage and asset backed securities | — | 114 | — | 114 | ||||||||||||
Other | — | 24 | — | 24 | ||||||||||||
Total | $ | 197 | $ | 558 | $ | — | $ | 755 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 21 | $ | — | $ | 21 | ||||||||
(a) | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||||||||||||||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | |||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity fund | $ | 121 | None | Monthly | 5 days | |||||||||||
Other — commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Other — money market funds | 11 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Nuclear decommissioning trusts: | ||||||||||||||||
Foreign equity fund | $ | 131 | None | Daily | 5 days | |||||||||||
Corporate bonds — commingled funds | 8 | None | Daily | Not applicable | ||||||||||||
Other — commingled funds | 24 | None | Daily | Not applicable | ||||||||||||
Financial instruments not having carrying amount equal to fair value | As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 9,797 | $ | 10,552 | ||||||||||||
2013 | $ | 8,593 | $ | 8,782 | ||||||||||||
Gulf Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 125 | $ | — | $ | 125 | ||||||||
Cash equivalents | 18,032 | — | — | 18,032 | ||||||||||||
Total | $ | 18,032 | $ | 125 | $ | — | $ | 18,157 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 72,435 | $ | — | $ | 72,435 | ||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant | Significant | ||||||||||||||
Other | Unobservable | |||||||||||||||
Observable | Inputs | |||||||||||||||
Inputs | ||||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 6,962 | $ | — | $ | 6,962 | ||||||||
Cash equivalents | 15,929 | — | — | 15,929 | ||||||||||||
Total | $ | 15,929 | $ | 6,962 | $ | — | $ | 22,891 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 17,043 | $ | — | $ | 17,043 | ||||||||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | |||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in thousands) | |||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $18,032 | None | Daily | Not applicable | ||||||||||||
As of December 31, 2013: | ||||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $15,929 | None | Daily | Not applicable | ||||||||||||
Financial instruments not having carrying amount equal to fair value | As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in thousands) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 1,369,594 | $ | 1,476,954 | ||||||||||||
2013 | $ | 1,233,163 | $ | 1,261,889 | ||||||||||||
Mississippi Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 65 | $ | — | $ | 65 | ||||||||
Cash equivalents | 114,900 | — | — | 114,900 | ||||||||||||
Total | $ | 114,900 | $ | 65 | $ | — | $ | 114,965 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 45,429 | $ | — | $ | 45,429 | ||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 4,803 | $ | — | $ | 4,803 | ||||||||
Cash equivalents | 125,000 | — | — | 125,000 | ||||||||||||
Total | $ | 125,000 | $ | 4,803 | $ | — | $ | 129,803 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 10,281 | $ | — | $ | 10,281 | ||||||||
Foreign currency derivatives | — | 1 | — | 1 | ||||||||||||
Total | $ | — | $ | 10,282 | $ | — | $ | 10,282 | ||||||||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | |||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in thousands) | |||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 114,900 | None | Daily | Not applicable | |||||||||||
As of December 31, 2013: | ||||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 125,000 | None | Daily | Not applicable | |||||||||||
Financial instruments not having carrying amount equal to fair value | As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in thousands) | ||||||||||||||||
Long-term debt: | ||||||||||||||||
2014 | $ | 2,328,476 | $ | 2,382,050 | ||||||||||||
2013 | $ | 2,098,639 | $ | 2,045,519 | ||||||||||||
Southern Power [Member] | ||||||||||||||||
Fair Value Disclosures [Line Items] | ||||||||||||||||
Assets and liabilities measured at fair value on a recurring basis | As of December 31, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | |||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2014: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 5.5 | $ | — | $ | 5.5 | ||||||||
Cash equivalents | 18 | — | — | 18 | ||||||||||||
Total | $ | 18 | $ | 5.5 | $ | — | $ | 23.5 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 3.6 | $ | — | $ | 3.6 | ||||||||
As of December 31, 2013, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows: | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||||||
As of December 31, 2013: | (Level 1) | (Level 2) | (Level 3) | Total | ||||||||||||
(in millions) | ||||||||||||||||
Assets: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 0.6 | $ | — | $ | 0.6 | ||||||||
Cash equivalents | 68 | — | — | 68 | ||||||||||||
Total | $ | 68 | $ | 0.6 | $ | — | $ | 68.6 | ||||||||
Liabilities: | ||||||||||||||||
Energy-related derivatives | $ | — | $ | 0.6 | $ | — | $ | 0.6 | ||||||||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | As of December 31, 2014 and 2013, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows: | |||||||||||||||
Fair | Unfunded | Redemption | Redemption | |||||||||||||
Value | Commitments | Frequency | Notice Period | |||||||||||||
As of December 31, 2014: | (in millions) | |||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 18 | None | Daily | Not applicable | |||||||||||
As of December 31, 2013: | ||||||||||||||||
Cash equivalents: | ||||||||||||||||
Money market funds | $ | 68 | None | Daily | Not applicable | |||||||||||
Financial instruments not having carrying amount equal to fair value | As of December 31, 2014 and 2013, other financial instruments for which the carrying amount did not equal fair value were as follows: | |||||||||||||||
Carrying | Fair | |||||||||||||||
Amount | Value | |||||||||||||||
(in millions) | ||||||||||||||||
Long-term debt, including securities due within one year: | ||||||||||||||||
2014 | $ | 1,621 | $ | 1,785 | ||||||||||||
2013 | $ | 1,620 | $ | 1,660 | ||||||||||||
Derivatives_Tables
Derivatives (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
Notional amount of interest rate derivatives | At December 31, 2014, the following interest rate derivatives were outstanding: | |||||||||||||||||||||||
Notional | Interest | Weighted Average Interest | Hedge | Fair Value | ||||||||||||||||||||
Amount | Rate | Rate Paid | Maturity | Gain (Loss) | ||||||||||||||||||||
Received | Date | December 31, | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Cash Flow Hedges of Forecasted Debt | ||||||||||||||||||||||||
$200 | 3-month LIBOR | 2.93% | Oct-25 | $ | (8 | ) | ||||||||||||||||||
350 | 3-month LIBOR | 2.57% | May-25 | (6 | ) | |||||||||||||||||||
350 | 3-month LIBOR | 2.57% | Nov-25 | (2 | ) | |||||||||||||||||||
Cash Flow Hedges of Existing Debt | ||||||||||||||||||||||||
250 | 3-month LIBOR + 0.32% | 0.75% | Mar-16 | — | ||||||||||||||||||||
200 | 3-month LIBOR + 0.40% | 1.01% | Aug-16 | — | ||||||||||||||||||||
Fair Value Hedges of Existing Debt | ||||||||||||||||||||||||
250 | 1.30% | 3-month LIBOR + 0.17% | Aug-17 | 1 | ||||||||||||||||||||
250 | 5.40% | 3-month LIBOR + 4.02% | Jun-18 | (1 | ) | |||||||||||||||||||
200 | 4.25% | 3-month LIBOR + 2.46% | Dec-19 | — | ||||||||||||||||||||
Total | $2,050 | $ | (16 | ) | ||||||||||||||||||||
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: | |||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 7 | $ | 16 | Other current liabilities | $ | 118 | $ | 26 | ||||||||||||||
Other deferred charges and assets | — | 7 | Other deferred credits and liabilities | 79 | 29 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 7 | $ | 23 | $ | 197 | $ | 55 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||||||||||||
Interest rate derivatives: | Other current assets | $ | 7 | $ | 3 | Other current liabilities | $ | 17 | $ | — | ||||||||||||||
Other deferred charges and assets | 1 | — | Other deferred credits and liabilities | 7 | — | |||||||||||||||||||
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 8 | $ | 3 | $ | 24 | $ | — | ||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Energy-related derivatives | Other current assets | $ | 6 | $ | — | Other current liabilities | $ | 4 | $ | 1 | ||||||||||||||
Other deferred charges and assets | — | 1 | Other deferred credits and liabilities | — | — | |||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | 6 | $ | 1 | $ | 4 | $ | 1 | ||||||||||||||||
Total | $ | 21 | $ | 27 | $ | 225 | $ | 56 | ||||||||||||||||
Balance sheet offsetting | Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | |||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 13 | $ | 24 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 201 | $ | 56 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (9 | ) | (22 | ) | Gross amounts not offset in the Balance Sheet (b) | (9 | ) | (22 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 4 | $ | 2 | Net energy-related derivative liabilities | $ | 192 | $ | 34 | |||||||||||||||
Interest rate derivatives presented in the Balance Sheet (a) | $ | 8 | $ | 3 | Interest rate derivatives presented in the Balance Sheet (a) | $ | 24 | $ | — | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (8 | ) | — | Gross amounts not offset in the Balance Sheet (b) | (8 | ) | — | |||||||||||||||||
Net interest rate derivative assets | $ | — | $ | 3 | Net interest rate derivative liabilities | $ | 16 | $ | — | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
Pre-tax effects on the balance sheets | At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | |||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (118 | ) | $ | (26 | ) | Other regulatory liabilities, current | $ | 7 | $ | 16 | ||||||||||||
Other regulatory assets, deferred | (79 | ) | (29 | ) | Other regulatory liabilities, deferred | — | 7 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (197 | ) | $ | (55 | ) | $ | 7 | $ | 23 | ||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
Notional amount of interest rate derivatives | At December 31, 2014, the following interest rate derivatives were outstanding: | |||||||||||||||||||||||
Notional | Interest | Weighted Average Interest | Hedge | Fair Value | ||||||||||||||||||||
Amount | Rate | Rate Paid | Maturity | Gain (Loss) | ||||||||||||||||||||
Received | Date | December 31, | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Cash Flow Hedges of Forecasted Debt | ||||||||||||||||||||||||
$200 | 3-month | 2.93% | Oct-25 | $ | (8 | ) | ||||||||||||||||||
LIBOR | ||||||||||||||||||||||||
Energy-related derivative contracts | At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: | |||||||||||||||||||||||
Net Purchased | Longest Hedge | Longest Non-Hedge | ||||||||||||||||||||||
mmBtu | Date | Date | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
56 | 2017 | — | ||||||||||||||||||||||
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: | |||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 1 | $ | 5 | Other current liabilities | $ | 32 | $ | 3 | ||||||||||||||
Other deferred charges and assets | — | 2 | Other deferred credits and liabilities | 21 | 5 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 1 | $ | 7 | $ | 53 | $ | 8 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow hedges | ||||||||||||||||||||||||
Interest rate derivatives: | Other current assets | $ | — | $ | — | Other current liabilities | $ | 8 | $ | — | ||||||||||||||
Total | $ | 1 | $ | 7 | $ | 61 | $ | 8 | ||||||||||||||||
Balance sheet offsetting | Some of these energy-related and interest rate derivative contracts contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure table below. | |||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 1 | $ | 7 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 53 | $ | 8 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | — | (5 | ) | Gross amounts not offset in the Balance Sheet (b) | — | (5 | ) | |||||||||||||||||
Net energy-related derivative assets | $ | 1 | $ | 2 | Net energy-related derivative liabilities | $ | 53 | $ | 3 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
Pre-tax effects on the balance sheets | At December 31, 2014 and 2013, the pre-tax effect of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets was as follows: | |||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (32 | ) | $ | (3 | ) | Other current liabilities | $ | 1 | $ | 5 | ||||||||||||
Other regulatory assets, deferred | (21 | ) | (5 | ) | Other regulatory liabilities, deferred | — | 2 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (53 | ) | $ | (8 | ) | $ | 1 | $ | 7 | ||||||||||||||
Pre-tax effects on the statements of income | For the years ended December 31, 2014, 2013, and 2012, the pre-tax effect of interest rate derivatives designated as cash flow hedging instruments on the statements of income was as follows: | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Recognized in | Gain (Loss) Reclassified from Accumulated OCI into Income | ||||||||||||||||||||||
OCI on Derivative | (Effective Portion) | |||||||||||||||||||||||
(Effective Portion) | Amount | |||||||||||||||||||||||
Derivative Category | 2014 | 2013 | 2012 | Statements of Income | 2014 | 2013 | 2012 | |||||||||||||||||
Location | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Interest rate derivatives | $ | (8 | ) | $ | — | $ | (18 | ) | Interest expense, net of amounts capitalized | $ | (3 | ) | $ | (3 | ) | $ | (3 | ) | ||||||
Georgia Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
Notional amount of interest rate derivatives | At December 31, 2014, the following interest rate derivatives were outstanding: | |||||||||||||||||||||||
Notional | Interest | Weighted Average Interest | Hedge | Fair Value | ||||||||||||||||||||
Amount | Rate | Rate Paid | Maturity | Gain (Loss) | ||||||||||||||||||||
Received | Date | December 31, | ||||||||||||||||||||||
2014 | ||||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Cash Flow Hedges of Forecasted Debt | ||||||||||||||||||||||||
$ | 350 | 3-month LIBOR | 2.57% | May-25 | $ | (6 | ) | |||||||||||||||||
350 | 3-month LIBOR | 2.57% | Nov-25 | (2 | ) | |||||||||||||||||||
Cash Flow Hedges of Existing Debt | ||||||||||||||||||||||||
250 | 3-month LIBOR + 0.32% | 0.75% | Mar-16 | — | ||||||||||||||||||||
200 | 3-month LIBOR + 0.40% | 1.01% | Aug-16 | — | ||||||||||||||||||||
Fair value hedges of existing debt | ||||||||||||||||||||||||
250 | 5.40% | 3-month LIBOR + 4.02% | Jun-18 | (1 | ) | |||||||||||||||||||
200 | 4.25% | 3-month LIBOR + 2.46% | Dec-19 | — | ||||||||||||||||||||
Total | $ | 1,600 | $ | (9 | ) | |||||||||||||||||||
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2014 and 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows: | |||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 6 | $ | 3 | Liabilities from risk management activities | $ | 23 | $ | 13 | ||||||||||||||
Other deferred charges and assets | 1 | 2 | Other deferred credits and liabilities | 4 | 8 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 7 | $ | 5 | $ | 27 | $ | 21 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||||||||||||
Interest rate derivatives: | Other current assets | $ | 5 | $ | — | Liabilities from risk management activities | $ | 9 | $ | — | ||||||||||||||
Other deferred charges and assets | 1 | — | Other deferred credits and liabilities | 5 | — | |||||||||||||||||||
Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 6 | $ | — | $ | 14 | $ | — | ||||||||||||||||
Total | $ | 13 | $ | 5 | $ | 41 | $ | 21 | ||||||||||||||||
Balance sheet offsetting | Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts and interest rate derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | |||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 7 | $ | 5 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 27 | $ | 21 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (7 | ) | (5 | ) | Gross amounts not offset in the Balance Sheet (b) | (7 | ) | (5 | ) | |||||||||||||||
Net energy-related derivative assets | $ | — | $ | — | Net energy-related derivative liabilities | $ | 20 | $ | 16 | |||||||||||||||
Interest rate derivatives presented in the Balance Sheet (a) | $ | 6 | $ | — | Interest rate derivatives presented in the Balance Sheet (a) | $ | 14 | $ | — | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (6 | ) | — | Gross amounts not offset in the Balance Sheet (b) | (6 | ) | — | |||||||||||||||||
Net interest rate derivative assets | $ | — | $ | — | Net interest rate derivative liabilities | $ | 8 | $ | — | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
Pre-tax effects on the balance sheets | At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | |||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (23 | ) | $ | (13 | ) | Other regulatory liabilities, current | $ | 6 | $ | 3 | ||||||||||||
Other regulatory assets, deferred | (4 | ) | (8 | ) | Other deferred credits and liabilities | 1 | 2 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (27 | ) | $ | (21 | ) | $ | 7 | $ | 5 | ||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2014 and 2013, the fair value of energy-related derivatives was reflected in the balance sheets as follows: | |||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet Location | 2014 | 2013 | ||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 34 | $ | 4,893 | Liabilities from risk management activities | $ | 36,922 | $ | 6,470 | ||||||||||||||
Other deferred charges and assets | 78 | 2,069 | Other deferred credits and liabilities | 35,502 | 10,573 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 112 | $ | 6,962 | $ | 72,424 | $ | 17,043 | ||||||||||||||||
Balance sheet offsetting | Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | |||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 125 | $ | 6,962 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 72,435 | $ | 17,043 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (123 | ) | (5,775 | ) | Gross amounts not offset in the Balance Sheet (b) | (123 | ) | (5,775 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 2 | $ | 1,187 | Net energy-related derivative liabilities | $ | 72,312 | $ | 11,268 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
Pre-tax effects on the balance sheets | At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | |||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (36,922 | ) | $ | (6,470 | ) | Other regulatory liabilities, current | $ | 34 | $ | 4,893 | ||||||||||||
Other regulatory assets, deferred | (35,502 | ) | (10,573 | ) | Other regulatory liabilities, deferred | 78 | 2,069 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (72,424 | ) | $ | (17,043 | ) | $ | 112 | $ | 6,962 | ||||||||||||||
Pre-tax effects on the statements of income | For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows: | |||||||||||||||||||||||
Derivatives in Cash | Gain (Loss) Recognized in | Gain (Loss) Reclassified from Accumulated | ||||||||||||||||||||||
Flow Hedging Relationships | OCI on Derivative | OCI into Income (Effective Portion) | ||||||||||||||||||||||
(Effective Portion) | Amount | |||||||||||||||||||||||
Derivative Category | 2014 | 2013 | 2012 | Statements of Income Location | 2014 | 2013 | 2012 | |||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Interest rate derivatives | $— | $— | $— | Interest expense, net of amounts capitalized | ($606) | ($769) | ($933) | |||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
Energy-related derivative contracts | At December 31, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Company, together with the longest hedge date over which it is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest date for derivatives not designated as hedges, were as follows: | |||||||||||||||||||||||
Net Purchased | Longest Hedge | Longest Non-Hedge | ||||||||||||||||||||||
mmBtu | Date | Date | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
54 | 2018 | — | ||||||||||||||||||||||
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2014 and 2013, the fair value of energy-related derivatives and foreign currency derivatives was reflected in the balance sheets as follows: | |||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet Location | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | ||||||||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||||||||||||
Energy-related derivatives: | Other current assets | $ | 30 | $ | 3,352 | Other current liabilities | $ | 26,259 | $ | 3,652 | ||||||||||||||
Other deferred charges and assets | 22 | 1,451 | Other deferred credits and liabilities | 19,159 | 6,629 | |||||||||||||||||||
Total derivatives designated as hedging instruments for regulatory purposes | $ | 52 | $ | 4,803 | $ | 45,418 | $ | 10,281 | ||||||||||||||||
Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||||||||||||
Foreign currency derivatives: | Other current assets | $ | — | $ | — | Other current liabilities | $ | — | $ | 1 | ||||||||||||||
Total | $ | 52 | $ | 4,803 | $ | 45,418 | $ | 10,282 | ||||||||||||||||
Balance sheet offsetting | Amounts related to energy-related derivative contracts at December 31, 2014 and 2013 are presented in the following tables. | |||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 65 | $ | 4,803 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 45,429 | $ | 10,282 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (64 | ) | (3,856 | ) | Gross amounts not offset in the Balance Sheet (b) | (64 | ) | (3,856 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 1 | $ | 947 | Net energy-related derivative liabilities | $ | 45,365 | $ | 6,426 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
Pre-tax effects on the balance sheets | At December 31, 2014 and 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows: | |||||||||||||||||||||||
Unrealized Losses | Unrealized Gains | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives: | Other regulatory assets, current | $ | (26,259 | ) | $ | (3,652 | ) | Other regulatory liabilities, current | $ | 30 | $ | 3,352 | ||||||||||||
Other regulatory assets, deferred | (19,159 | ) | (6,629 | ) | Other regulatory liabilities, deferred | 22 | 1,451 | |||||||||||||||||
Total energy-related derivative gains (losses) | $ | (45,418 | ) | $ | (10,281 | ) | $ | 52 | $ | 4,803 | ||||||||||||||
Pre-tax effects on the statements of income | For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of derivatives designated as cash flow hedging instruments on the statements of operations were as follows: | |||||||||||||||||||||||
Derivatives in Cash Flow | Gain (Loss) Recognized in | Gain (Loss) Reclassified from Accumulated | ||||||||||||||||||||||
Hedging Relationships | OCI on Derivative | OCI into Income | ||||||||||||||||||||||
(Effective Portion) | (Effective Portion) | |||||||||||||||||||||||
Amount | ||||||||||||||||||||||||
Derivative Category | 2014 | 2013 | 2012 | Statements of Operations Location | 2014 | 2013 | 2012 | |||||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||||||
Energy-related derivatives | $ | — | $ | — | $ | — | Fuel | $ | — | $ | — | $ | — | |||||||||||
Interest rate derivatives | — | — | (774 | ) | Interest Expense | (1,375 | ) | (1,375 | ) | (1,073 | ) | |||||||||||||
Total | $ | — | $ | — | $ | (774 | ) | $ | (1,375 | ) | $ | (1,375 | ) | $ | (1,073 | ) | ||||||||
Southern Power [Member] | ||||||||||||||||||||||||
Derivative [Line Items] | ||||||||||||||||||||||||
Fair value of energy-related derivatives and interest rate derivatives | At December 31, 2014 and 2013, the fair value of energy-related derivatives was reflected in the balance sheets as follows: | |||||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivative Category | Balance Sheet | 2014 | 2013 | Balance Sheet | 2014 | 2013 | ||||||||||||||||||
Location | Location | |||||||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Derivatives not designated as hedging instruments | ||||||||||||||||||||||||
Energy-related derivatives: | Assets from risk management activities | $ | 5.3 | $ | 0.2 | Other current liabilities | $ | 3.5 | $ | 0.6 | ||||||||||||||
Other deferred charges and assets – non-affiliated | 0.2 | 0.4 | Other deferred credits and liabilities – non-affiliated | 0.1 | — | |||||||||||||||||||
Total derivatives not designated as hedging instruments | $ | 5.5 | $ | 0.6 | $ | 3.6 | $ | 0.6 | ||||||||||||||||
Balance sheet offsetting | Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below. | |||||||||||||||||||||||
Fair Value | ||||||||||||||||||||||||
Assets | 2014 | 2013 | Liabilities | 2014 | 2013 | |||||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||||||
Energy-related derivatives presented in the Balance Sheet (a) | $ | 5.5 | $ | 0.6 | Energy-related derivatives presented in the Balance Sheet (a) | $ | 3.6 | $ | 0.6 | |||||||||||||||
Gross amounts not offset in the Balance Sheet (b) | (0.1 | ) | (0.1 | ) | Gross amounts not offset in the Balance Sheet (b) | (0.1 | ) | (0.1 | ) | |||||||||||||||
Net energy-related derivative assets | $ | 5.4 | $ | 0.5 | Net energy-related derivative liabilities | $ | 3.5 | $ | 0.5 | |||||||||||||||
(a) | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||||||||||||||||||||||
(b) | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||||||||||||||||||||||
Pre-tax effects on the statements of income | For the years ended December 31, 2014, 2013, and 2012, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on the statements of income were as follows: | |||||||||||||||||||||||
Derivatives in Cash Flow Hedging Relationships | Gain (Loss) Reclassified from AOCI into Income | |||||||||||||||||||||||
(Effective Portion) | ||||||||||||||||||||||||
Amount | ||||||||||||||||||||||||
Derivative Category | Statements of Income Location | 2014 | 2013 | 2012 | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Energy-related derivatives | Depreciation and amortization | $ | 0.4 | $ | 0.4 | $ | 0.4 | |||||||||||||||||
Interest rate derivatives | Interest expense, net of amounts capitalized | (0.9 | ) | (6.5 | ) | (10.5 | ) | |||||||||||||||||
Total | $ | (0.5 | ) | $ | (6.1 | ) | $ | (10.1 | ) |
Segment_and_Related_Informatio1
Segment and Related Information (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||||||||||||||
Financial data for business segments | Financial data for business segments and products and services for the years ended December 31, 2014, 2013, and 2012 was as follows: | |||||||||||||||||||||||||||
Electric Utilities | ||||||||||||||||||||||||||||
Traditional | Southern | Eliminations | Total | All | Eliminations | Consolidated | ||||||||||||||||||||||
Operating | Power | Other | ||||||||||||||||||||||||||
Companies | ||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
2014 | ||||||||||||||||||||||||||||
Operating revenues | $ | 17,354 | $ | 1,501 | $ | (449 | ) | $ | 18,406 | $ | 159 | $ | (98 | ) | $ | 18,467 | ||||||||||||
Depreciation and amortization | 1,709 | 220 | — | 1,929 | 16 | — | 1,945 | |||||||||||||||||||||
Interest income | 17 | 1 | — | 18 | 3 | (2 | ) | 19 | ||||||||||||||||||||
Interest expense | 705 | 89 | — | 794 | 43 | (2 | ) | 835 | ||||||||||||||||||||
Income taxes | 1,056 | (3 | ) | — | 1,053 | (76 | ) | — | 977 | |||||||||||||||||||
Segment net income (loss)(a) (b) | 1,797 | 172 | — | 1,969 | (3 | ) | (3 | ) | 1,963 | |||||||||||||||||||
Total assets | 64,644 | 5,550 | (131 | ) | 70,063 | 1,156 | (296 | ) | 70,923 | |||||||||||||||||||
Gross property additions | 5,568 | 942 | — | 6,510 | 11 | 1 | 6,522 | |||||||||||||||||||||
2013 | ||||||||||||||||||||||||||||
Operating revenues | $ | 16,136 | $ | 1,275 | $ | (376 | ) | $ | 17,035 | $ | 139 | $ | (87 | ) | $ | 17,087 | ||||||||||||
Depreciation and amortization | 1,711 | 175 | — | 1,886 | 15 | — | 1,901 | |||||||||||||||||||||
Interest income | 17 | 1 | — | 18 | 2 | (1 | ) | 19 | ||||||||||||||||||||
Interest expense | 714 | 74 | — | 788 | 36 | — | 824 | |||||||||||||||||||||
Income taxes | 889 | 46 | — | 935 | (85 | ) | (1 | ) | 849 | |||||||||||||||||||
Segment net income (loss)(a) (b) | 1,486 | 166 | — | 1,652 | (10 | ) | 2 | 1,644 | ||||||||||||||||||||
Total assets | 59,447 | 4,429 | (101 | ) | 63,775 | 1,077 | (306 | ) | 64,546 | |||||||||||||||||||
Gross property additions | 5,226 | 633 | — | 5,859 | 9 | — | 5,868 | |||||||||||||||||||||
2012 | ||||||||||||||||||||||||||||
Operating revenues | $ | 15,730 | $ | 1,186 | $ | (438 | ) | $ | 16,478 | $ | 141 | $ | (82 | ) | $ | 16,537 | ||||||||||||
Depreciation and amortization | 1,629 | 143 | — | 1,772 | 15 | — | 1,787 | |||||||||||||||||||||
Interest income | 21 | 1 | — | 22 | 19 | (1 | ) | 40 | ||||||||||||||||||||
Interest expense | 757 | 63 | — | 820 | 39 | — | 859 | |||||||||||||||||||||
Income taxes | 1,307 | 93 | — | 1,400 | (66 | ) | — | 1,334 | ||||||||||||||||||||
Segment net income (loss)(a) | 2,145 | 175 | 1 | 2,321 | 33 | (4 | ) | 2,350 | ||||||||||||||||||||
Total assets | 58,600 | 3,780 | (129 | ) | 62,251 | 1,116 | (218 | ) | 63,149 | |||||||||||||||||||
Gross property additions | 4,813 | 241 | — | 5,054 | 5 | — | 5,059 | |||||||||||||||||||||
(a) | After dividends on preferred and preference stock of subsidiaries. | |||||||||||||||||||||||||||
(b) | Segment net income (loss) for the traditional operating companies in 2014 and 2013 includes $868 million in pre-tax charges ($536 million after tax) and $1.2 billion in pre-tax charges ($729 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information. | |||||||||||||||||||||||||||
Financial data for products and services | Products and Services | |||||||||||||||||||||||||||
Electric Utilities' Revenues | ||||||||||||||||||||||||||||
Year | Retail | Wholesale | Other | Total | ||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
2014 | $15,550 | $2,184 | $672 | $18,406 | ||||||||||||||||||||||||
2013 | 14,541 | 1,855 | 639 | 17,035 | ||||||||||||||||||||||||
2012 | 14,187 | 1,675 | 616 | 16,478 |
Noncontrolling_Interest_Tables
Noncontrolling Interest (Tables) (Southern Power [Member]) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Southern Power [Member] | ||||||||||||
Noncontrolling Interest [Line Items] | ||||||||||||
Redeemable Noncontrolling Interest | The following table details the components of redeemable noncontrolling interests for the years ended December 31: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Beginning balance | $ | 28.8 | $ | 8.1 | $ | 3.8 | ||||||
Net income attributable to redeemable noncontrolling interest | 4 | 3.9 | 0.9 | |||||||||
Distributions to redeemable noncontrolling interest | (1.1 | ) | (0.5 | ) | — | |||||||
Capital contributions from redeemable noncontrolling interest | 7.5 | 17.3 | 3.4 | |||||||||
Ending balance | $ | 39.2 | $ | 28.8 | $ | 8.1 | ||||||
Condensed Income Statement | For the year ended December 31, 2014, net income included in the consolidated statements of changes in stockholders' equity is reconciled to net income presented in the consolidated statements of income as follows: | |||||||||||
2014 | ||||||||||||
Net income attributable to Southern Power Company | $ | 172.3 | ||||||||||
Net loss attributable to noncontrolling interest | (1.2 | ) | ||||||||||
Net income attributable to redeemable noncontrolling interest | 4 | |||||||||||
Net income | $ | 175.1 | ||||||||||
Quarterly_Financial_Informatio1
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
Summarized quarterly financial data | Summarized quarterly financial information for 2014 and 2013 is as follows: | |||||||||||||||||||||||||||||||
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries | Per Common Share | |||||||||||||||||||||||||||||||
Operating | Operating | Basic | Diluted Earnings | Trading | ||||||||||||||||||||||||||||
Revenues | Income | Earnings | Price Range | |||||||||||||||||||||||||||||
Quarter Ended | Dividends | High | Low | |||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 4,644 | $ | 700 | $ | 351 | $ | 0.39 | $ | 0.39 | $ | 0.5075 | $ | 44 | $ | 40.27 | ||||||||||||||||
Jun-14 | 4,467 | 1,103 | 611 | 0.68 | 0.68 | 0.525 | 46.81 | 42.55 | ||||||||||||||||||||||||
Sep-14 | 5,339 | 1,278 | 718 | 0.8 | 0.8 | 0.525 | 45.47 | 41.87 | ||||||||||||||||||||||||
Dec-14 | 4,017 | 561 | 283 | 0.31 | 0.31 | 0.525 | 51.28 | 43.55 | ||||||||||||||||||||||||
Mar-13 | $ | 3,897 | $ | 325 | $ | 81 | $ | 0.09 | $ | 0.09 | $ | 0.49 | $ | 46.95 | $ | 42.82 | ||||||||||||||||
Jun-13 | 4,246 | 640 | 297 | 0.34 | 0.34 | 0.5075 | 48.74 | 42.32 | ||||||||||||||||||||||||
Sep-13 | 5,017 | 1,491 | 852 | 0.97 | 0.97 | 0.5075 | 45.75 | 40.63 | ||||||||||||||||||||||||
Dec-13 | 3,927 | 799 | 414 | 0.47 | 0.47 | 0.5075 | 42.94 | 40.03 | ||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
Summarized quarterly financial data | Summarized quarterly financial information for 2014 and 2013 is as follows: | |||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income After Dividends on Preferred and Preference Stock | |||||||||||||||||||||||||||||
Revenues | Income | |||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 1,508 | $ | 381 | $ | 187 | ||||||||||||||||||||||||||
Jun-14 | 1,437 | 357 | 173 | |||||||||||||||||||||||||||||
Sep-14 | 1,669 | 520 | 282 | |||||||||||||||||||||||||||||
Dec-14 | 1,328 | 267 | 119 | |||||||||||||||||||||||||||||
Mar-13 | $ | 1,308 | $ | 307 | $ | 141 | ||||||||||||||||||||||||||
Jun-13 | 1,392 | 357 | 173 | |||||||||||||||||||||||||||||
Sep-13 | 1,604 | 500 | 258 | |||||||||||||||||||||||||||||
Dec-13 | 1,314 | 312 | 140 | |||||||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
Summarized quarterly financial data | Summarized quarterly financial information for 2014 and 2013 is as follows: | |||||||||||||||||||||||||||||||
Quarter Ended | Operating Revenues | Operating Income | Net Income After Dividends on Preferred and Preference Stock | |||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 2,269 | $ | 516 | $ | 266 | ||||||||||||||||||||||||||
Jun-14 | 2,186 | 572 | 311 | |||||||||||||||||||||||||||||
Sep-14 | 2,631 | 920 | 525 | |||||||||||||||||||||||||||||
Dec-14 | 1,902 | 288 | 123 | |||||||||||||||||||||||||||||
Mar-13 | $ | 1,882 | $ | 412 | $ | 197 | ||||||||||||||||||||||||||
Jun-13 | 2,042 | 552 | 282 | |||||||||||||||||||||||||||||
Sep-13 | 2,484 | 872 | 487 | |||||||||||||||||||||||||||||
Dec-13 | 1,866 | 404 | 208 | |||||||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
Summarized quarterly financial data | Summarized quarterly financial information for 2014 and 2013 is as follows: | |||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income After Dividends on Preference Stock | |||||||||||||||||||||||||||||
Revenues | Income | |||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 407,132 | $ | 73,888 | $ | 36,743 | ||||||||||||||||||||||||||
Jun-14 | 383,531 | 68,877 | 34,097 | |||||||||||||||||||||||||||||
Sep-14 | 438,334 | 88,600 | 46,547 | |||||||||||||||||||||||||||||
Dec-14 | 361,485 | 49,850 | 22,789 | |||||||||||||||||||||||||||||
Mar-13 | $ | 326,274 | $ | 51,640 | $ | 21,792 | ||||||||||||||||||||||||||
Jun-13 | 371,173 | 69,151 | 32,582 | |||||||||||||||||||||||||||||
Sep-13 | 399,361 | 87,776 | 44,754 | |||||||||||||||||||||||||||||
Dec-13 | 343,493 | 56,436 | 25,301 | |||||||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
Summarized quarterly financial data | Summarized quarterly financial information for 2014 and 2013 is as follows: | |||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income (Loss) After Dividends on Preferred Stock | |||||||||||||||||||||||||||||
Revenues | Income (Loss) | |||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 331,161 | $ | (325,460 | ) | $ | (172,048 | ) | ||||||||||||||||||||||||
Jun-14 | 310,975 | 56,021 | 62,495 | |||||||||||||||||||||||||||||
Sep-14 | 354,623 | (349,010 | ) | (195,070 | ) | |||||||||||||||||||||||||||
Dec-14 | 245,852 | (70,721 | ) | (24,058 | ) | |||||||||||||||||||||||||||
Mar-13 | $ | 245,934 | $ | (429,148 | ) | $ | (246,321 | ) | ||||||||||||||||||||||||
Jun-13 | 306,435 | (388,395 | ) | (219,110 | ) | |||||||||||||||||||||||||||
Sep-13 | 325,206 | (79,890 | ) | (24,115 | ) | |||||||||||||||||||||||||||
Dec-13 | 267,582 | (24,412 | ) | 12,921 | ||||||||||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information [Line Items] | ||||||||||||||||||||||||||||||||
Summarized quarterly financial data | Summarized quarterly financial information for 2014 and 2013 is as follows: | |||||||||||||||||||||||||||||||
Quarter Ended | Operating | Operating | Net Income | |||||||||||||||||||||||||||||
Revenues | Income | Attributable to | ||||||||||||||||||||||||||||||
Southern Power Company | ||||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||
Mar-14 | $ | 350,854 | $ | 59,358 | $ | 33,471 | ||||||||||||||||||||||||||
Jun-14 | 328,803 | 51,073 | 30,812 | |||||||||||||||||||||||||||||
Sep-14 | 435,256 | 104,710 | 63,631 | |||||||||||||||||||||||||||||
Dec-14 | 386,336 | 40,138 | 44,386 | |||||||||||||||||||||||||||||
Mar-13 | $ | 302,947 | $ | 64,673 | $ | 29,192 | ||||||||||||||||||||||||||
Jun-13 | 307,255 | 55,024 | 27,922 | |||||||||||||||||||||||||||||
Sep-13 | 364,767 | 116,497 | 85,153 | |||||||||||||||||||||||||||||
Dec-13 | 300,257 | 53,781 | 23,266 | |||||||||||||||||||||||||||||
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) (USD $) | 12 Months Ended | 0 Months Ended | 24 Months Ended | 60 Months Ended | 1 Months Ended | |||
Dec. 31, 2014 | Jan. 01, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Jan. 31, 2012 | ||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | $4,664,000,000 | $4,664,000,000 | $2,624,000,000 | |||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | |||||||
Asset retirement obligations-liability [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -130,000,000 | [1],[2] | -130,000,000 | [1],[2] | -139,000,000 | [1],[2] | ||
Other cost of removal obligations [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -1,229,000,000 | [1] | -1,229,000,000 | [1] | -1,289,000,000 | [1] | ||
Deferred income tax credits [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -192,000,000 | [1] | -192,000,000 | [1] | -203,000,000 | [1] | ||
Property damage reserves [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -181,000,000 | [3] | -181,000,000 | [3] | -191,000,000 | [3] | ||
Property Damage Reserves Asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 98,000,000 | [4] | 98,000,000 | [4] | 37,000,000 | [4] | ||
Other regulatory liabilities [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -95,000,000 | [5] | -95,000,000 | [5] | -126,000,000 | [5] | ||
Nuclear outage [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 99,000,000 | [6] | 99,000,000 | [6] | 78,000,000 | [6] | ||
Kemper Regulatory Deferral [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -271,000,000 | [7] | -271,000,000 | [7] | -91,000,000 | [7] | ||
Deferred income tax charges [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 1,458,000,000 | [1] | 1,458,000,000 | [1] | 1,376,000,000 | [1] | ||
Deferred income tax charges - Medicare subsidy [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 57,000,000 | [8] | 57,000,000 | [8] | 65,000,000 | [8] | ||
Asset retirement obligations-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 119,000,000 | [1],[2] | 119,000,000 | [1],[2] | 145,000,000 | [1],[2] | ||
Loss on reacquired debt [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 267,000,000 | [9] | 267,000,000 | [9] | 293,000,000 | [9] | ||
Vacation pay [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 177,000,000 | [10],[2] | 177,000,000 | [10],[2] | 171,000,000 | [10],[2] | ||
Under recovered regulatory clause revenues [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 157,000,000 | [6] | 157,000,000 | [6] | 70,000,000 | [6] | ||
Canceled construction projects [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 67,000,000 | [11] | 67,000,000 | [11] | 70,000,000 | [11] | ||
PPA charges [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 185,000,000 | [12],[2] | 185,000,000 | [12],[2] | 180,000,000 | [12],[2] | ||
Fuel hedging-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 202,000,000 | [13],[2] | 202,000,000 | [13],[2] | 58,000,000 | [13],[2] | ||
Other regulatory assets [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 195,000,000 | [14] | 195,000,000 | [14] | 222,000,000 | [14] | ||
Environmental remediation-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 64,000,000 | [15],[2] | 64,000,000 | [15],[2] | 62,000,000 | [15],[2] | ||
Regulatory assets associated with Kemper IGCC [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 148,000,000 | [7] | 148,000,000 | [7] | 76,000,000 | [7] | ||
Retiree benefit plans [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 3,469,000,000 | [16],[2] | 3,469,000,000 | [16],[2] | 1,760,000,000 | [16],[2] | ||
Maximum [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 15 years | |||||||
Life of New Issue | 50 years | |||||||
Fuel Hedging Assets and Liabilities, Amortization Period | 5 years | |||||||
Power Purchase Agreement Period | 9 years | |||||||
Amortization Period For Other Regulatory Assets | 10 years | |||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 15 years | |||||||
Amortization Period For Other Regulatory Liabilities | 10 years | |||||||
Maximum [Member] | Environmental Controls [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Amortization Period For Other Regulatory Assets | 9 years | |||||||
Maximum [Member] | Property Damage Reserves Asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Amortization Period For Other Regulatory Assets | 8 years | |||||||
Alabama Power [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 738,000,000 | 738,000,000 | 92,000,000 | |||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | |||||||
Medicare Drug Subsidy Obligation Related To Subsidiary | 18,000,000 | 18,000,000 | 20,000,000 | |||||
Amortization Period for Regulatory Deferrals | 5 years | |||||||
Alabama Power [Member] | Asset retirement obligations-liability [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -125,000,000 | [17] | -125,000,000 | [17] | -132,000,000 | [17] | ||
Alabama Power [Member] | Other cost of removal obligations [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -744,000,000 | [17] | -744,000,000 | [17] | -828,000,000 | [17] | ||
Alabama Power [Member] | Deferred income tax credits [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -72,000,000 | [17] | -72,000,000 | [17] | -75,000,000 | [17] | ||
Alabama Power [Member] | Other regulatory liabilities [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -8,000,000 | [18],[19] | -8,000,000 | [18],[19] | -11,000,000 | [18],[19] | ||
Alabama Power [Member] | Fuel hedging-liability [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -1,000,000 | [20] | -1,000,000 | [20] | -8,000,000 | [20] | ||
Alabama Power [Member] | Nuclear outage [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 56,000,000 | [18] | 56,000,000 | [18] | 51,000,000 | [18] | ||
Alabama Power [Member] | Nuclear disaster reserve [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -84,000,000 | [21] | -84,000,000 | [21] | -96,000,000 | [21] | ||
Alabama Power [Member] | Retiree benefit plans [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 882,000,000 | [2],[22] | 882,000,000 | [2],[22] | 461,000,000 | [2],[22] | ||
Alabama Power [Member] | Regulatory Deferrals [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 13,000,000 | [23] | 13,000,000 | [23] | 20,000,000 | [23] | ||
Alabama Power [Member] | Nuclear Fuel Disposal Fee [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -8,000,000 | [24] | -8,000,000 | [24] | 0 | [24] | ||
Alabama Power [Member] | Deferred income tax charges [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 525,000,000 | [17],[25] | 525,000,000 | [17],[25] | 519,000,000 | [17],[25] | ||
Alabama Power [Member] | Loss on reacquired debt [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 80,000,000 | [26] | 80,000,000 | [26] | 86,000,000 | [26] | ||
Alabama Power [Member] | Vacation pay [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 65,000,000 | [10],[2] | 65,000,000 | [10],[2] | 63,000,000 | [10],[2] | ||
Alabama Power [Member] | Under recovered regulatory clause revenues [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 57,000,000 | [18] | 57,000,000 | [18] | -18,000,000 | [18] | ||
Alabama Power [Member] | Fuel hedging-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 53,000,000 | [20] | 53,000,000 | [20] | 8,000,000 | [20] | ||
Alabama Power [Member] | Other regulatory assets [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 49,000,000 | [27] | 49,000,000 | [27] | 52,000,000 | [27] | ||
Alabama Power [Member] | Maximum [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 15 years | |||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 50 years | |||||||
Life of New Issue | 50 years | |||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by PSCs | 10 years | |||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 15 years | |||||||
Georgia Power [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 2,529,000,000 | 2,529,000,000 | 1,886,000,000 | |||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 13 years | |||||||
Other Cost of Removal Obligations Related to Subsidiary | 29,000,000 | 29,000,000 | ||||||
Amortization Period of Other Cost of Removal Obligations | 2 years | 3 years | 3 years | |||||
Fuel Hedging Assets and Liabilities, Amortization Period | 2 years | |||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | |||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 8 years | |||||||
Refueling Cycles Maximum Period | 24 months | |||||||
Period for Environmental Construction | 9 years | 9 years | ||||||
Georgia Power [Member] | Other cost of removal obligations [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -60,000,000 | [28] | -60,000,000 | [28] | -58,000,000 | [28] | ||
Georgia Power [Member] | Deferred income tax credits [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -106,000,000 | [28] | -106,000,000 | [28] | -112,000,000 | [28] | ||
Georgia Power [Member] | Other regulatory liabilities [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -7,000,000 | [29] | -7,000,000 | [29] | -6,000,000 | |||
Georgia Power [Member] | Deferred income tax charges [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 668,000,000 | [28] | 668,000,000 | [28] | 684,000,000 | [28] | ||
Georgia Power [Member] | Deferred income tax charges - Medicare subsidy [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 34,000,000 | [30] | 34,000,000 | [30] | 38,000,000 | [30] | ||
Georgia Power [Member] | Asset retirement obligations-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 108,000,000 | [28] | 108,000,000 | [28] | 137,000,000 | [28] | ||
Georgia Power [Member] | Loss on reacquired debt [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 163,000,000 | [31] | 163,000,000 | [31] | 181,000,000 | [31] | ||
Georgia Power [Member] | Vacation pay [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 91,000,000 | [10] | 91,000,000 | [10] | 88,000,000 | [10] | ||
Georgia Power [Member] | Canceled construction projects [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 67,000,000 | [32] | 67,000,000 | [32] | 70,000,000 | [32] | ||
Georgia Power [Member] | Fuel hedging-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 29,000,000 | [33] | 29,000,000 | [33] | 22,000,000 | [33] | ||
Georgia Power [Member] | Other regulatory assets [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 63,000,000 | [30] | 63,000,000 | [30] | 49,000,000 | [30] | ||
Georgia Power [Member] | Retiree benefit plans [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 1,325,000,000 | [34] | 1,325,000,000 | [34] | 691,000,000 | [34] | ||
Georgia Power [Member] | Remaining Net Book Value Of Retired Units [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 25,000,000 | [29] | 25,000,000 | [29] | 28,000,000 | [29] | ||
Georgia Power [Member] | Storm Reserve [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 98,000,000 | [30] | 98,000,000 | [30] | 37,000,000 | [30] | ||
Georgia Power [Member] | Building Leases [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 31,000,000 | [35] | 31,000,000 | [35] | 37,000,000 | [35] | ||
Georgia Power [Member] | Maximum [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 70 years | |||||||
Life of New Issue | 38 years | |||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 10 years | |||||||
Gulf Power [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 319,644,000 | 319,644,000 | 160,224,000 | |||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Life of New Issue | 40 years | |||||||
Fuel Hedging Assets and Liabilities, Amortization Period | 5 years | |||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | |||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 1 year | |||||||
Gulf Power [Member] | Asset retirement obligations-liability [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -5,087,000 | [2],[36] | -5,087,000 | [2],[36] | -6,089,000 | [2],[36] | ||
Gulf Power [Member] | Other cost of removal obligations [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -242,997,000 | [36] | -242,997,000 | [36] | -228,148,000 | [36] | ||
Gulf Power [Member] | Regulatory Cost of Removal Credit [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 8,410,000 | [37] | 8,410,000 | [37] | 0 | [37] | ||
Gulf Power [Member] | Deferred income tax credits [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -3,872,000 | [36] | -3,872,000 | [36] | -5,238,000 | [36] | ||
Gulf Power [Member] | Property damage reserves [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -35,111,000 | [38] | -35,111,000 | [38] | -35,380,000 | [38] | ||
Gulf Power [Member] | Other regulatory liabilities [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -649,000 | [2],[38] | -649,000 | [2],[38] | -8,804,000 | [2],[38] | ||
Gulf Power [Member] | Fuel hedging-liability [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -112,000 | [2],[35] | -112,000 | [2],[35] | -6,962,000 | [2],[35] | ||
Gulf Power [Member] | Deferred income tax charges [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 53,234,000 | [36] | 53,234,000 | [36] | 47,573,000 | [36] | ||
Gulf Power [Member] | Deferred income tax charges - Medicare subsidy [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 3,024,000 | [39] | 3,024,000 | [39] | 3,351,000 | [39] | ||
Gulf Power [Member] | Loss on reacquired debt [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 15,991,000 | [40] | 15,991,000 | [40] | 16,565,000 | [40] | ||
Gulf Power [Member] | Vacation pay [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 10,006,000 | [10],[2] | 10,006,000 | [10],[2] | 9,521,000 | [10],[2] | ||
Gulf Power [Member] | Under recovered regulatory clause revenues [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 52,619,000 | [41] | 52,619,000 | [41] | 45,191,000 | [41] | ||
Gulf Power [Member] | PPA charges [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 185,065,000 | [2],[42] | 185,065,000 | [2],[42] | 180,149,000 | [2],[42] | ||
Gulf Power [Member] | Fuel hedging-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 73,474,000 | [2],[35] | 73,474,000 | [2],[35] | 17,043,000 | [2],[35] | ||
Gulf Power [Member] | Other regulatory assets [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 9,753,000 | [43] | 9,753,000 | [43] | 12,772,000 | [43] | ||
Gulf Power [Member] | Environmental remediation-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 48,271,000 | [15],[2] | 48,271,000 | [15],[2] | 50,384,000 | [15],[2] | ||
Gulf Power [Member] | Retiree benefit plans [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 147,625,000 | [2],[44] | 147,625,000 | [2],[44] | 68,296,000 | [2],[44] | ||
Gulf Power [Member] | Maximum [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 14 years | |||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 65 years | |||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 14 years | |||||||
Recovered and Amortization Periods as Approved by Appropriate State Public Service Commission | 9 years | |||||||
Gulf Power [Member] | Maximum [Member] | Generation Site Selection Evaluation Costs [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 8 years | |||||||
Mississippi Power [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 171,764,000 | 171,764,000 | 66,604,000 | |||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 14 years | |||||||
Fuel Hedging Assets and Liabilities, Amortization Period | 4 years | |||||||
Amortization Period of Regulatory Assets and Liabilities | 50 years | |||||||
Mississippi Power [Member] | Other cost of removal obligations [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -165,999,000 | [45] | -165,999,000 | [45] | -156,683,000 | [45] | ||
Mississippi Power [Member] | Deferred income tax credits [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -9,370,000 | [45] | -9,370,000 | [45] | -10,191,000 | [45] | ||
Mississippi Power [Member] | Property damage reserves [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -61,648,000 | [46] | -61,648,000 | [46] | -60,092,000 | [46] | ||
Mississippi Power [Member] | Other regulatory liabilities [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -4,198,000 | [47] | -4,198,000 | [47] | -8,855,000 | [47] | ||
Mississippi Power [Member] | Mirror Construction Work In Progress [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | -270,779,000 | [7] | -270,779,000 | [7] | -90,524,000 | [7] | ||
Mississippi Power [Member] | Deferred income tax charges [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 222,599,000 | [45] | 222,599,000 | [45] | 140,185,000 | [45] | ||
Mississippi Power [Member] | Asset retirement obligations-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 10,845,000 | [45] | 10,845,000 | [45] | 8,918,000 | [45] | ||
Mississippi Power [Member] | Loss on reacquired debt [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 8,542,000 | [48] | 8,542,000 | [48] | 9,178,000 | [48] | ||
Mississippi Power [Member] | Vacation pay [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 11,172,000 | [10],[2] | 11,172,000 | [10],[2] | 10,214,000 | [10],[2] | ||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | |||||||
Mississippi Power [Member] | Fuel hedging-asset [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 46,631,000 | [2],[49] | 46,631,000 | [2],[49] | 10,340,000 | [2],[49] | ||
Mississippi Power [Member] | Other regulatory assets [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 16,270,000 | [47] | 16,270,000 | [47] | 5,415,000 | [47] | ||
Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 147,689,000 | [7] | 147,689,000 | [7] | 75,873,000 | [7] | ||
Mississippi Power [Member] | Property tax [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 27,680,000 | [50] | 27,680,000 | [50] | 31,206,000 | [50] | ||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Amortization Period of Regulatory Assets and Liabilities | 12 months | |||||||
Mississippi Power [Member] | Retiree Benefit Plans - Regulatory Assets [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 169,317,000 | [2],[51] | 169,317,000 | [2],[51] | 82,799,000 | [2],[51] | ||
Mississippi Power [Member] | Plant Daniel Units 3 and 4 [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities [Line Items] | ||||||||
Total assets (liabilities), net | 23,013,000 | [52] | 23,013,000 | [52] | 18,821,000 | [52] | ||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by PSCs | 10 years | |||||||
Amortization Period of Regulatory Assets and Liabilities | 10 years | |||||||
Regulatory Assets Associated with Asset Retirement Obligations [Member] | Mississippi Power [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Amortization Period of Regulatory Assets and Liabilities | 49 years | |||||||
Settlement Agreement [Member] | Gulf Power [Member] | ||||||||
Schedule of Regulatory Assets and Liabilities - Other Information [Abstract] | ||||||||
Other Cost of Removal Obligations Related to Subsidiary | $8,400,000 | $8,400,000 | ||||||
[1] | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. At DecemberB 31, 2014, other cost of removal obligations included $29 million that will be amortized over the two-year period from January 2015 through December 2016 in accordance with Georgia Power's 2013 ARP. See Note 3 under "Retail Regulatory Matters b Georgia Power b Rate Plans" for additional information. At DecemberB 31, 2014, other cost of removal obligations included $8.4 million recorded as authorized by the Florida PSC in the Settlement Agreement approved in December 2013 (Gulf Power Settlement Agreement). | |||||||
[2] | Not earning a return as offset in rate base by a corresponding asset or liability. | |||||||
[3] | Recovered as storm restoration and potential reliability-related expenses are incurred as approved by the appropriate state PSCs. | |||||||
[4] | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods generally not exceeding eight years. | |||||||
[5] | Comprised of numerous immaterial components including over-recovered regulatory clause revenues, fuel-hedging liabilities, mine reclamation and remediation liabilities, PPA credits, nuclear disposal fees, and other liabilities that are recorded and recovered or amortized as approved by the appropriate state PSCs generally over periods not exceeding 10 years. | |||||||
[6] | Recorded and recovered or amortized as approved or accepted by the appropriate state PSCs over periods not exceeding 10 years. | |||||||
[7] | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle b Rate Recovery of Kemper IGCC Costs b Regulatory Assets and Liabilities." | |||||||
[8] | Recovered and amortized as approved by the appropriate state PSCs over periods not exceeding 15 years. | |||||||
[9] | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which may range up to 50 years. | |||||||
[10] | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | |||||||
[11] | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||
[12] | Recovered over the life of the PPA for periods up to nine years. | |||||||
[13] | Recorded over the life of the underlying hedged purchase contracts, which generally do not exceed five years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||
[14] | Comprised of numerous immaterial components including property taxes, generation site selection/evaluation costs, demand side management cost deferrals, regulatory deferrals, building leases, net book value of retired generating units, Plant Daniel Units 3 and 4 regulatory assets, and other miscellaneous assets. These costs are recorded and recovered or amortized as approved by the appropriate state PSC over periods generally not exceeding 10 years or, as applicable, over the remaining life of the asset but not beyond 2031 | |||||||
[15] | Recovered through the environmental cost recovery clause when the remediation is performed. | |||||||
[16] | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | |||||||
[17] | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 50 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||
[18] | Recorded and recovered or amortized as approved or accepted by the Alabama PSC over periods not exceeding 10 years. | |||||||
[19] | Comprised of components including mine reclamation and remediation liabilities and other liabilities. Recorded as accepted by the Alabama PSC. Mine reclamation and remediation liabilities will be settled following completion of the related activities. | |||||||
[20] | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed three years. Upon final settlement, actual costs incurred are recovered through the energy cost recovery clause. | |||||||
[21] | Utilized as storm restoration and potential reliability-related expenses are incurred, as approved by the Alabama PSC. | |||||||
[22] | Recovered and amortized over the average remaining service period which may range up to 15 years. See NoteB 2 for additional information. | |||||||
[23] | Recorded and amortized as approved by the Alabama PSC for a period of five years. | |||||||
[24] | Recorded as approved by the Alabama PSC related to potential future fees for nuclear waste disposal. The term of deferral is conditional upon resolution by the DOE. See Note 3 for additional information. | |||||||
[25] | Included in the deferred income tax charges are $18 million for 2014 and $20 million for 2013 for the retiree Medicare drug subsidy, which is recovered and amortized, as approved by the Alabama PSC, over the average remaining service period which may range up to 15 years. | |||||||
[26] | Recovered over the remaining life of the original issue, which may range up to 50 years. | |||||||
[27] | Comprised of components including generation site selection/evaluation costs, PPA capacity, and other miscellaneous assets. Recorded as accepted by the Alabama PSC. Capitalized upon initialization of related construction projects, if applicable. | |||||||
[28] | Asset retirement and other cost of removal obligations and deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 70 years. Asset retirement and removal liabilities will be settled and trued up following completion of the related activities. At December 31, 2014, other cost of removal obligations included $29 million that will be amortized over the remaining two-year period of January 2015 through December 2016 in accordance with the Company's 2013 ARP. | |||||||
[29] | Amortized as approved by the Georgia PSC over periods not exceeding 10 years or through 2022. | |||||||
[30] | Recorded and recovered or amortized as approved by the Georgia PSC over periods generally not exceeding eight years. | |||||||
[31] | Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue, which currently does not exceed 38 years. | |||||||
[32] | Costs associated with construction of environmental controls that will not be completed as a result of unit retirements are being amortized as approved by the Georgia PSC over periods not exceeding nine years or through 2022. | |||||||
[33] | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed two years. Upon final settlement, actual costs incurred are recovered through the Company's fuel cost recovery mechanism. | |||||||
[34] | Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 2 for additional information. | |||||||
[35] | See Note 6 under "Capital Leases." Recovered over the remaining life of the building through 2020. | |||||||
[36] | Asset retirement and removal assets and liabilities are recorded, deferred income tax assets are recovered, and deferred income tax liabilities are amortized over the related property lives, which may range up to 65 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||
[37] | Recorded as authorized by the Florida PSC in a settlement agreement approved in December 2013. See Note 3 for additional information. | |||||||
[38] | Recorded and recovered or amortized as approved by the Florida PSC. | |||||||
[39] | Recovered and amortized over periods not exceeding 14 years. | |||||||
[40] | Recovered over either the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 40 years. | |||||||
[41] | Recorded and recovered or amortized as approved by the Florida PSC, generally within one year. | |||||||
[42] | (k)Recovered over the life of the PPA for periods | |||||||
[43] | o nine years.(l)Comprised primarily of net book value of retired meters, deferred rate case expenses, and generation site evaluation costs. These costs are recorded and recovered or amortized as approved by the Florida PSC, generally over periods not exceeding eight years, or deferred pursuant to Florida statute while the Company continues to evaluate certain potential new generating | |||||||
[44] | Recovered and amortized over the average remaining service period which may range up to 14 years. See NoteB 2 for additional information. | |||||||
[45] | Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | |||||||
[46] | For additional information, see Note 1 under "Provision for Property Damage." | |||||||
[47] | Recorded and recovered (amortized) as approved by the Mississippi PSC. | |||||||
[48] | Recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue, which may range up to 50 years. | |||||||
[49] | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the ECM. | |||||||
[50] | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. | |||||||
[51] | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||
[52] | Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Property, Plant, and Equipment (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | $37,892,000,000 | $35,360,000,000 |
Transmission | 9,884,000,000 | 9,289,000,000 |
Distribution | 17,123,000,000 | 16,499,000,000 |
General | 4,198,000,000 | 3,958,000,000 |
Plant acquisition adjustment | 123,000,000 | 123,000,000 |
Utility plant in service | 69,220,000,000 | 65,229,000,000 |
Information technology equipment and software | 244,000,000 | 242,000,000 |
Communications equipment | 439,000,000 | 437,000,000 |
Other | 110,000,000 | 113,000,000 |
Other plant in service | 793,000,000 | 792,000,000 |
Total plant in service | 70,013,000,000 | 66,021,000,000 |
Alabama Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 11,670,000,000 | 11,314,000,000 |
Transmission | 3,579,000,000 | 3,287,000,000 |
Distribution | 6,196,000,000 | 5,934,000,000 |
General | 1,623,000,000 | 1,545,000,000 |
Plant acquisition adjustment | 12,000,000 | 12,000,000 |
Total plant in service | 23,080,000,000 | 22,092,000,000 |
Georgia Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 15,201,000,000 | 14,872,000,000 |
Transmission | 5,086,000,000 | 4,859,000,000 |
Distribution | 8,913,000,000 | 8,620,000,000 |
General | 1,855,000,000 | 1,753,000,000 |
Plant acquisition adjustment | 28,000,000 | 28,000,000 |
Total plant in service | 31,083,000,000 | 30,132,000,000 |
Gulf Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 2,637,817,000 | 2,607,166,000 |
Transmission | 515,754,000 | 473,378,000 |
Distribution | 1,156,872,000 | 1,117,024,000 |
General | 182,734,000 | 164,065,000 |
Plant acquisition adjustment | 1,776,000 | 2,031,000 |
Total plant in service | 4,494,953,000 | 4,363,664,000 |
Mississippi Power [Member] | ||
Public Utilities, Property, Plant and Equipment, Plant in Service [Abstract] | ||
Generation | 2,293,511,000 | 1,475,264,000 |
Transmission | 664,618,000 | 633,903,000 |
Distribution | 853,835,000 | 828,470,000 |
General | 484,711,000 | 439,721,000 |
Plant acquisition adjustment | 81,412,000 | 81,412,000 |
Total plant in service | $4,378,087,000 | $3,458,770,000 |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Purchase of the Plant Daniel Combined Cycle Generating Units (Details) (Mississippi Power [Member], Plant Daniel Units 3 and 4 [Member], USD $) | Dec. 31, 2012 |
In Millions, unless otherwise specified | |
Mississippi Power [Member] | Plant Daniel Units 3 and 4 [Member] | |
Significant Acquisitions and Disposals [Line Items] | |
Fair value adjustment at date of purchase | $76.10 |
Total debt | $346.10 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies - Capital Leased Assets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Accumulated Amortization | ($49) | ($48) |
Capital Leased Assets, Net of Amortization | 161 | 164 |
Office Building [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | 61 | 61 |
Nitrogen Plant [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | 83 | 83 |
Computer-Related Equipment [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | 60 | 62 |
Gas Pipeline [Member] | ||
Capital Leased Assets [Line Items] | ||
Capital Leased Assets, Gross | $6 | $6 |
Summary_of_Significant_Account7
Summary of Significant Accounting Policies - Business Acquisitions (Details) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | |||||
In Millions, unless otherwise specified | Nov. 26, 2014 | Nov. 06, 2014 | Dec. 31, 2014 | Dec. 31, 2014 | 22-May-14 | Apr. 17, 2014 | Apr. 23, 2013 | ||
MW | MW | ||||||||
Business Acquisition [Line Items] | |||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 100.00% | 100.00% | |||||||
Southern Power [Member] | Turner Renewable Energy [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 10.00% | 10.00% | |||||||
Southern Power [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
MW Capacity | 150 | 150 | [1],[2] | 150 | [1],[2] | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 51.00% | [1],[2] | 51.00% | [1],[2] | |||||
Year of Operation | 2014 | 2014 | [1],[2] | ||||||
PPA Contract Period | 25 years | 25 years | [1],[2] | ||||||
Payments to Acquire Businesses, Gross | $504.70 | $504.70 | [1],[2] | ||||||
Southern Power [Member] | Macho Springs, LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
MW Capacity | 50 | [3],[4] | 50 | [3],[4] | 50 | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 90.00% | [3],[4] | 90.00% | [3],[4] | |||||
Year of Operation | 2014 | [3],[4] | |||||||
PPA Contract Period | 20 years | [3],[4] | 20 years | ||||||
Payments to Acquire Businesses, Gross | 130 | [3],[4] | 130 | ||||||
Southern Power [Member] | Adobe Solar LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
MW Capacity | 20 | [3],[4] | 20 | [3],[4] | 20 | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 90.00% | [3],[4] | 90.00% | [3],[4] | 90.00% | ||||
Year of Operation | 2014 | [3],[4] | 2014 | ||||||
PPA Contract Period | 20 years | [3],[4] | 20 years | ||||||
Payments to Acquire Businesses, Gross | 96.2 | [3],[4] | 96.2 | ||||||
Southern Power [Member] | Campo Verde Solar LLC [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
MW Capacity | 139 | [3],[4],[5] | 139 | [3],[4],[5] | 139 | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 90.00% | [3],[4],[5] | 90.00% | [3],[4],[5] | |||||
Year of Operation | 2013 | [3],[4],[5] | 2013 | ||||||
PPA Contract Period | 20 years | [3],[4],[5] | 20 years | ||||||
Payments to Acquire Businesses, Gross | 136.6 | [3],[4],[5] | 136.6 | ||||||
Business Acquisition Cost of Acquired Entity Purchase Consideration Cash Will Be Paid | $355.50 | ||||||||
[1] | Reflects Southern Power's portion of the purchase price. | ||||||||
[2] | This acquisition was made by Southern Power through its subsidiaries Southern Renewable Partnerships, LLC and SG2 Holdings, LLC. SG2 Holdings, LLC is jointly-owned by Southern Power and First Solar, Inc. | ||||||||
[3] | Reflects 100% of the purchase price, including Turner Renewable Energy, LLC's 10% equity contribution. | ||||||||
[4] | This acquisition was made by Southern Power and Turner Renewable Energy, LLC through Southern Turner Renewable Energy, LLC. | ||||||||
[5] | Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar, Inc. to complete the construction of the solar facility. |
Summary_of_Significant_Account8
Summary of Significant Accounting Policies - Intangible Assets (Details) (Southern Power [Member], USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Southern Power [Member] | |
Acquired Finite-Lived Intangible Assets [Line Items] | |
2015 | $2.50 |
2016 | 2.4 |
2017 | 2.5 |
2018 | 2.5 |
2019 | 2.5 |
2020 and beyond | 28.5 |
Total | $40.90 |
Summary_of_Significant_Account9
Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | $2,018,000 | $1,757,000 |
Liabilities incurred | 18,000 | 6,000 |
Liabilities settled | -17,000 | -16,000 |
Accretion | 102,000 | 97,000 |
Cash flow revisions | 80,000 | 174,000 |
Balance at end of year | 2,201,000 | 2,018,000 |
Alabama Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 730,000 | 589,000 |
Liabilities incurred | 1,000 | 0 |
Liabilities settled | -3,000 | -1,000 |
Accretion | 45,000 | 40,000 |
Cash flow revisions | 56,000 | 102,000 |
Balance at end of year | 829,000 | 730,000 |
Georgia Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 1,222,000 | 1,105,000 |
Liabilities incurred | 9,000 | 2,000 |
Liabilities settled | -12,000 | -13,000 |
Accretion | 53,000 | 55,000 |
Cash flow revisions | -17,000 | 73,000 |
Balance at end of year | 1,255,000 | 1,222,000 |
Gulf Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 16,184 | 16,055 |
Liabilities incurred | 0 | 518 |
Liabilities settled | -32 | -1,913 |
Accretion | 718 | 751 |
Cash flow revisions | -159 | 773 |
Balance at end of year | 16,711 | 16,184 |
Mississippi Power [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | 41,910 | 42,115 |
Liabilities settled | -2,529 | -24 |
Accretion | 1,969 | 1,840 |
Cash flow revisions | 6,898 | -2,021 |
Balance at end of year | $48,248 | $41,910 |
Recovered_Sheet1
Summary of Significant Accounting Policies - Accumulated Provisions and Estimated Costs For Decommissioning (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Alabama Power [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | $775 | $734 |
Decommissioning | ||
Total site study costs | 1,442 | |
Alabama Power [Member] | Plant Farley [Member] | ||
Decommissioning | ||
Beginning Year | 2037 | |
Completion Year | 2076 | |
Alabama Power [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 754 | 713 |
Alabama Power [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 21 | 21 |
Alabama Power [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 1,362 | |
Alabama Power [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 80 | |
Plant Farley [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 775 | 734 |
Decommissioning | ||
Beginning Year | 2037 | |
Completion Year | 2076 | |
Total site study costs | 1,442 | |
Plant Farley [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 754 | 713 |
Plant Farley [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 21 | 21 |
Plant Farley [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 1,362 | |
Plant Farley [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 0 | |
Plant Farley [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 80 | |
Plant Hatch [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 496 | 469 |
Decommissioning | ||
Beginning Year | 2034 | |
Completion Year | 2068 | |
Total site study costs | 731 | |
Plant Hatch [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 496 | 469 |
Plant Hatch [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 0 | 0 |
Plant Hatch [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 549 | |
Plant Hatch [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 131 | |
Plant Hatch [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 51 | |
Plant Hatch [Member] | Georgia Power [Member] | ||
Decommissioning | ||
Beginning Year | 2034 | |
Completion Year | 2068 | |
Total site study costs | 731 | |
External trust funds | 496 | |
Plant Hatch [Member] | Georgia Power [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 549 | |
Plant Hatch [Member] | Georgia Power [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 131 | |
Plant Hatch [Member] | Georgia Power [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 51 | |
Plant Vogtle [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 293 | 277 |
Decommissioning | ||
Beginning Year | 2047 | |
Completion Year | 2072 | |
Total site study costs | 644 | |
Plant Vogtle [Member] | Accumulated Provisions for Decommissioning External Trust Funds [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 293 | 277 |
Plant Vogtle [Member] | Accumulated Provisions for Decommissioning Internal Reserves [Member] | ||
Accumulated Provisions for Decommissioning | ||
Total | 0 | 0 |
Plant Vogtle [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 453 | |
Plant Vogtle [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 115 | |
Plant Vogtle [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 76 | |
Plant Vogtle [Member] | Georgia Power [Member] | ||
Decommissioning | ||
Beginning Year | 2047 | |
Completion Year | 2072 | |
Total site study costs | 644 | |
External trust funds | 293 | |
Plant Vogtle [Member] | Georgia Power [Member] | Site Study Cost Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | 453 | |
Plant Vogtle [Member] | Georgia Power [Member] | Spent Fuel Management [Member] | ||
Decommissioning | ||
Total site study costs | 115 | |
Plant Vogtle [Member] | Georgia Power [Member] | Site Study Cost Non-Radiated Structures [Member] | ||
Decommissioning | ||
Total site study costs | $76 |
Recovered_Sheet2
Summary of Significant Accounting Policies - Leveraged Leases (Details) (Domestic And International Leveraged Lease [Member], USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Domestic And International Leveraged Lease [Member] | |||
Net Investments from Leveraged Lease | |||
Net rentals receivable | $1,495 | $1,440 | |
Unearned income | -752 | -775 | |
Investment in leveraged leases | 743 | 665 | |
Deferred taxes from leveraged leases | -299 | -287 | |
Net investment in leveraged leases | 444 | 378 | |
Components of Income from Leveraged Lease | |||
Pretax leveraged lease income | 24 | -5 | 21 |
Income tax expense | -9 | 2 | -8 |
Net leveraged lease income | $15 | ($3) | $13 |
Recovered_Sheet3
Summary of Significant Accounting Policies - Comprehensive Income (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | ($75,000) | ||
Current period change | -53,000 | 48,000 | -12,000 |
Ending Balance | -128,000 | -75,000 | |
Qualifying Hedges [Member] | |||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | -36,000 | ||
Current period change | -5,000 | ||
Ending Balance | -41,000 | ||
Marketable Securities [Member] | |||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | 0 | ||
Current period change | 0 | ||
Ending Balance | 0 | ||
Pension and Other Postretirement Benefit Plans [Member] | |||
Change in Accumulated OCI (loss) balances [Roll Forward] | |||
Beginning Balance | -39,000 | ||
Current period change | -48,000 | ||
Ending Balance | ($87,000) |
Recovered_Sheet4
Summary of Significant Accounting Policies - Customer Revenues (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 10.00% | ||
Customer Concentration Risk [Member] | Southern Power [Member] | Florida Power and Light [Member] | Sales Revenue, Goods, Net [Member] | |||
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 10.10% | 11.80% | 12.80% |
Customer Concentration Risk [Member] | Southern Power [Member] | Georgia Power [Member] | Sales Revenue, Goods, Net [Member] | |||
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 9.70% | 10.70% | 12.50% |
Customer Concentration Risk [Member] | Southern Power [Member] | Progress Energy Florida [Member] | Sales Revenue, Goods, Net [Member] | |||
Concentration Risk [Line Items] | |||
Maximum Revenue from Single Customer or Industry | 9.10% | 10.30% | 5.90% |
Recovered_Sheet5
Summary of Significant Accounting Policies - Affiliate Transactions (Details) (Southern Power [Member], USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Related Party Transaction [Line Items] | ||
Related Party Transaction, Amounts of Transaction | ($12.40) | ($17.60) |
Deferred Capacity Revenues Affiliated [Member] | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Amounts of Transaction | -15.3 | -15.3 |
Other Current Liabilities [Member] | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Amounts of Transaction | 0 | -4.2 |
Other Deferred Charges and assets - Affiliated [Member] | ||
Related Party Transaction [Line Items] | ||
Related Party Transaction, Amounts of Transaction | $2.90 | $1.90 |
Recovered_Sheet6
Summary of Significant Accounting Policies - Textual (Details) (USD $) | 12 Months Ended | 2 Months Ended | 12 Months Ended | 24 Months Ended | 60 Months Ended | 1 Months Ended | 0 Months Ended | 3 Months Ended | 1 Months Ended | ||||||||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2011 | Dec. 31, 2014 | Dec. 31, 2013 | Jan. 31, 2012 | Nov. 06, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 19, 2014 | Dec. 31, 2010 | Sep. 30, 2013 | ||||||||
Property | MW | ||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | $860,000,000 | ||||||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Maximum revenue from a single customer or industry | 10.00% | ||||||||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | ||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Non-cash property additions recognized | 528,000,000 | 411,000,000 | 524,000,000 | ||||||||||||||||||
Income Tax Matters [Abstract] | |||||||||||||||||||||
Amortization of deferred investment tax credits | 22,000,000 | 16,000,000 | 23,000,000 | ||||||||||||||||||
Credits amortized to income tax expense | 11,400,000 | 5,500,000 | 2,600,000 | ||||||||||||||||||
Federal Investment Tax Credits | 74,000,000 | 158,000,000 | 45,000,000 | ||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 24,059,000,000 | 23,059,000,000 | 24,059,000,000 | 24,059,000,000 | 23,059,000,000 | 24,059,000,000 | 23,059,000,000 | ||||||||||||||
Plant acquisition adjustment | 123,000,000 | 123,000,000 | 123,000,000 | 123,000,000 | 123,000,000 | 123,000,000 | 123,000,000 | ||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 1,546,000,000 | 1,465,000,000 | 1,546,000,000 | 1,546,000,000 | 1,465,000,000 | 1,546,000,000 | 1,465,000,000 | ||||||||||||||
Proceeds from sale of securities held in external trust funds | 913,000,000 | 1,000,000,000 | 1,000,000,000 | ||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 98,000,000 | 181,000,000 | 137,000,000 | ||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | |||||||||||||||||||||
AFUDC, net of income taxes | 16.00% | 15.00% | 8.20% | ||||||||||||||||||
Cash payments for interest totaled | 732,000,000 | 759,000,000 | 803,000,000 | ||||||||||||||||||
Net of amounts capitalized | 111,000,000 | 92,000,000 | 83,000,000 | ||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 4,664,000,000 | 2,624,000,000 | 4,664,000,000 | 4,664,000,000 | 2,624,000,000 | 4,664,000,000 | 2,624,000,000 | ||||||||||||||
Other Regulatory Assets Current | 346,000,000 | 207,000,000 | 346,000,000 | 346,000,000 | 207,000,000 | 346,000,000 | 207,000,000 | ||||||||||||||
Other Regulatory Assets Deferred | 4,334,000,000 | 2,495,000,000 | 4,334,000,000 | 4,334,000,000 | 2,495,000,000 | 4,334,000,000 | 2,495,000,000 | ||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Other Cost of Removal Obligations | 1,215,000,000 | 1,275,000,000 | 1,215,000,000 | 1,215,000,000 | 1,275,000,000 | 1,215,000,000 | 1,275,000,000 | ||||||||||||||
Previously Recorded Asset Retirement Obligation | 506,000,000 | ||||||||||||||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||||||||||||||||||||
Reduction Of Income Tax Expense | 48,000,000 | 31,000,000 | 8,000,000 | ||||||||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | 245,000,000 | 190,000,000 | 143,000,000 | ||||||||||||||||||
Maximum [Member] | |||||||||||||||||||||
Leveraged Leases [Abstract] | |||||||||||||||||||||
Leveraged lease agreement term | 45 years | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Life of New Issue | 50 years | ||||||||||||||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 15 years | ||||||||||||||||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 15 years | ||||||||||||||||||||
Plant Hatch [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Estimated cost of decommissioning completion year | 2068 | ||||||||||||||||||||
Plant Vogtle [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Estimated cost of decommissioning completion year | 2072 | ||||||||||||||||||||
Equity Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 886,000,000 | 896,000,000 | 886,000,000 | 886,000,000 | 896,000,000 | 886,000,000 | 896,000,000 | ||||||||||||||
Debt Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 638,000,000 | 528,000,000 | 638,000,000 | 638,000,000 | 528,000,000 | 638,000,000 | 528,000,000 | ||||||||||||||
Other Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 19,000,000 | 40,000,000 | 19,000,000 | 19,000,000 | 40,000,000 | 19,000,000 | 40,000,000 | ||||||||||||||
Securities Held in Funds [Member] | Realized Gain [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 2,000,000 | 5,000,000 | 4,000,000 | ||||||||||||||||||
Securities Held in Funds [Member] | Unrealized Gain [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 19,000,000 | 119,000,000 | 75,000,000 | ||||||||||||||||||
Utility Plant in Service [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.10% | 3.30% | 3.20% | ||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 23,500,000,000 | 22,500,000,000 | 23,500,000,000 | 23,500,000,000 | 22,500,000,000 | 23,500,000,000 | 22,500,000,000 | ||||||||||||||
Other Plant in Service [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 533,000,000 | 513,000,000 | 533,000,000 | 533,000,000 | 513,000,000 | 533,000,000 | 513,000,000 | ||||||||||||||
Other Plant in Service [Member] | Minimum [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Plant in service, estimated useful lives | 3 years | ||||||||||||||||||||
Other Plant in Service [Member] | Maximum [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Plant in service, estimated useful lives | 25 years | ||||||||||||||||||||
Recoverable Vacation Pay [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 177,000,000 | [1],[2] | 171,000,000 | [1],[2] | 177,000,000 | [1],[2] | 177,000,000 | [1],[2] | 171,000,000 | [1],[2] | 177,000,000 | [1],[2] | 171,000,000 | [1],[2] | |||||||
Retiree benefit plans [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 3,469,000,000 | [1],[3] | 1,760,000,000 | [1],[3] | 3,469,000,000 | [1],[3] | 3,469,000,000 | [1],[3] | 1,760,000,000 | [1],[3] | 3,469,000,000 | [1],[3] | 1,760,000,000 | [1],[3] | |||||||
Other Postretirement Benefits [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Other Regulatory Assets Deferred | 387,000,000 | 109,000,000 | 387,000,000 | 387,000,000 | 109,000,000 | 387,000,000 | 109,000,000 | ||||||||||||||
Monitoring Costs [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 140,000,000 | ||||||||||||||||||||
Southern Power [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Amortization of Intangible Assets | 2,500,000 | 2,500,000 | 1,700,000 | ||||||||||||||||||
Plant In Service Depreciated On A Units Of Production Basis | 470,200,000 | 470,200,000 | 470,200,000 | 470,200,000 | |||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | -12,400,000 | -17,600,000 | |||||||||||||||||||
Income Tax Matters [Abstract] | |||||||||||||||||||||
Amortization of deferred investment tax credits | 11,399,000 | 5,535,000 | 2,633,000 | ||||||||||||||||||
Credits amortized to income tax expense | 11,400,000 | 5,500,000 | 2,600,000 | ||||||||||||||||||
Reduction in tax basis of assets | 50.00% | ||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,034,610,000 | 871,963,000 | 1,034,610,000 | 1,034,610,000 | 871,963,000 | 1,034,610,000 | 871,963,000 | ||||||||||||||
Impairment of Long-Lived Assets and Intangibles | |||||||||||||||||||||
Average term of PPAs | 20 years | ||||||||||||||||||||
Deferred Project Development Costs | |||||||||||||||||||||
Deferred project development costs | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | 11,000,000 | ||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | |||||||||||||||||||||
Cash payments for interest totaled | 85,168,000 | 60,396,000 | 50,248,000 | ||||||||||||||||||
Net of amounts capitalized | -113,000 | 9,178,000 | 19,092,000 | ||||||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | ||||||||||||||||||||
Southern Power [Member] | Minimum [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Plant in service, estimated useful lives | 35 years | ||||||||||||||||||||
Southern Power [Member] | Maximum [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Plant in service, estimated useful lives | 45 years | ||||||||||||||||||||
Southern Power [Member] | Southern Renewable Energy, Inc. [Member] | |||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 90.00% | 90.00% | 90.00% | 90.00% | |||||||||||||||||
Southern Power [Member] | Turner Renewable Energy [Member] | |||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 10.00% | 10.00% | 10.00% | 10.00% | |||||||||||||||||
Southern Power [Member] | Southern Renewable Partnerships, LLC [Member] | |||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 51.00% | 51.00% | 51.00% | 51.00% | |||||||||||||||||
Southern Power [Member] | First Solar [Member] | |||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 49.00% | 49.00% | 49.00% | 49.00% | |||||||||||||||||
Southern Power [Member] | Southern Company Services, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 125,900,000 | 117,600,000 | 125,400,000 | ||||||||||||||||||
Southern Power [Member] | Operations and Maintenance Expense [Member] | Southern Company Services, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 124,800,000 | 114,300,000 | 107,700,000 | ||||||||||||||||||
Southern Power [Member] | Deferred Capacity Revenues Affiliated [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | -15,300,000 | -15,300,000 | |||||||||||||||||||
Southern Power [Member] | Electric Transmission [Member] | Southern Company Services, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 6,800,000 | 8,300,000 | 6,600,000 | ||||||||||||||||||
Southern Power [Member] | Florida Power and Light [Member] | Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | |||||||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Maximum revenue from a single customer or industry | 10.10% | 11.80% | 12.80% | ||||||||||||||||||
Southern Power [Member] | Progress Energy Florida [Member] | Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | |||||||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Maximum revenue from a single customer or industry | 9.10% | 10.30% | 5.90% | ||||||||||||||||||
Southern Power [Member] | Georgia Power [Member] | Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | |||||||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Maximum revenue from a single customer or industry | 9.70% | 10.70% | 12.50% | ||||||||||||||||||
Southern Power [Member] | Purchased Power from Affiliates [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 156,400,000 | 148,400,000 | 159,900,000 | ||||||||||||||||||
Southern Power [Member] | Operating Lease PPA [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 74,800,000 | 69,000,000 | 76,200,000 | ||||||||||||||||||
Gulf Power [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 62,000,000 | ||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Deferred capacity expense | 163,077,000 | 180,149,000 | 163,077,000 | 163,077,000 | 180,149,000 | 163,077,000 | 180,149,000 | ||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | ||||||||||||||||||||
Maximum revenue from a single customer or industry | 10.00% | ||||||||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | ||||||||||||||||||||
Income Tax Matters [Abstract] | |||||||||||||||||||||
Amortization of deferred investment tax credits | 1,300,000 | 1,400,000 | 1,400,000 | ||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.60% | 3.60% | 3.60% | ||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,295,714,000 | 1,211,336,000 | 1,295,714,000 | 1,295,714,000 | 1,211,336,000 | 1,295,714,000 | 1,211,336,000 | ||||||||||||||
Plant acquisition adjustment | 1,776,000 | 2,031,000 | 1,776,000 | 1,776,000 | 2,031,000 | 1,776,000 | 2,031,000 | ||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | |||||||||||||||||||||
Composite rate used to determine allowance for funds used during construction | 5.73% | 6.26% | 6.72% | 5.73% | 5.73% | 6.26% | 5.73% | 6.26% | |||||||||||||
AFUDC, net of income taxes | 10.93% | 6.87% | 5.36% | ||||||||||||||||||
Cash payments for interest totaled | 48,030,000 | 53,401,000 | 58,255,000 | ||||||||||||||||||
Net of amounts capitalized | 5,373,000 | 3,421,000 | 2,500,000 | ||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Accrued reserves | 35,700,000 | 35,400,000 | 35,700,000 | 35,700,000 | 35,400,000 | 35,700,000 | 35,400,000 | ||||||||||||||
Recovery Period For Natural Disaster Reserve Costs | 60 days | ||||||||||||||||||||
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation | 48,300,000 | 48,300,000 | 48,300,000 | 48,300,000 | |||||||||||||||||
PSC Approved Annual Property Damage Reserve Accrual | 3,500,000 | 3,500,000 | 3,500,000 | 3,500,000 | |||||||||||||||||
Threshold above which additional property damage reserves are authorized by PSC | 3,500,000 | 3,500,000 | 3,500,000 | 3,500,000 | |||||||||||||||||
Increase in accrued property damage costs | 3,500,000 | 3,500,000 | 3,500,000 | ||||||||||||||||||
Cumulative damage costs limit under PSC order | 100,000,000 | ||||||||||||||||||||
PSC approved annual uninsured injuries and damages accrual | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | |||||||||||||||||
Threshold above which additional uninsured injuries and damages accruals are authorized by PSC | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | |||||||||||||||||
Reserve for losses and loss adjustment expenses | 4,000,000 | 3,600,000 | 4,000,000 | 4,000,000 | 3,600,000 | 4,000,000 | 3,600,000 | ||||||||||||||
Net Regulatory Assets | 319,644,000 | 160,224,000 | 319,644,000 | 319,644,000 | 160,224,000 | 319,644,000 | 160,224,000 | ||||||||||||||
Other Regulatory Assets Current | 74,242,000 | 18,536,000 | 74,242,000 | 74,242,000 | 18,536,000 | 74,242,000 | 18,536,000 | ||||||||||||||
Other Regulatory Assets Deferred | 416,028,000 | 340,415,000 | 416,028,000 | 416,028,000 | 340,415,000 | 416,028,000 | 340,415,000 | ||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Other Cost of Removal Obligations | 234,587,000 | 228,148,000 | 234,587,000 | 234,587,000 | 228,148,000 | 234,587,000 | 228,148,000 | ||||||||||||||
Previously Recorded Asset Retirement Obligation | 6,000,000 | ||||||||||||||||||||
Life of New Issue | 40 years | ||||||||||||||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||||||||||||||||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 1 year | ||||||||||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | 12,021,000 | 6,448,000 | 5,221,000 | ||||||||||||||||||
Gulf Power [Member] | Minimum [Member] | |||||||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | ||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
PSC approved target level for property damage reserve | 48,000,000 | 48,000,000 | 48,000,000 | 48,000,000 | |||||||||||||||||
Gulf Power [Member] | Maximum [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 65 years | ||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Customer Surcharge Storm Recovery Costs | 4 | ||||||||||||||||||||
Customer Surcharge Storm Recovery Capacity | 1,000 | ||||||||||||||||||||
PSC approved target level for property damage reserve | 55,000,000 | 55,000,000 | 55,000,000 | 55,000,000 | |||||||||||||||||
PSC approved annual uninsured injuries and damages accrual | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | |||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 14 years | ||||||||||||||||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 14 years | ||||||||||||||||||||
Gulf Power [Member] | Plant Scherer Unit 3 [Member] | |||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 25.00% | 25.00% | 25.00% | 25.00% | |||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Plant acquisition adjustment | 1,800,000 | 1,800,000 | 1,800,000 | 1,800,000 | |||||||||||||||||
Gulf Power [Member] | Georgia Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 8,700,000 | 10,200,000 | 6,900,000 | ||||||||||||||||||
Gulf Power agreement, reimbursement of non-fuel expenses | 1,000,000 | 2,400,000 | 2,400,000 | ||||||||||||||||||
Gulf Power [Member] | Alabama Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Revenue Requirement Obligations | 132,000,000 | ||||||||||||||||||||
Revenue Requirements Reimbursement | 11,900,000 | 7,900,000 | 3,000,000 | ||||||||||||||||||
Gulf Power [Member] | Southern Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Long-term Purchase Commitment, Minimum Power Required | 292 | ||||||||||||||||||||
Gulf Power [Member] | Southern Company Services, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 79,600,000 | 78,400,000 | 95,900,000 | ||||||||||||||||||
Gulf Power [Member] | Mississippi Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 30,500,000 | 16,500,000 | 21,100,000 | ||||||||||||||||||
Gulf Power [Member] | Current Liabilities [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Reserve for losses and loss adjustment expenses | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | 1,600,000 | ||||||||||||||
Gulf Power [Member] | Deferred Credits and Other Liabilities [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Reserve for losses and loss adjustment expenses | 2,400,000 | 2,000,000 | 2,400,000 | 2,400,000 | 2,000,000 | 2,400,000 | 2,000,000 | ||||||||||||||
Gulf Power [Member] | Recoverable Vacation Pay [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 10,006,000 | [1],[2] | 9,521,000 | [1],[2] | 10,006,000 | [1],[2] | 10,006,000 | [1],[2] | 9,521,000 | [1],[2] | 10,006,000 | [1],[2] | 9,521,000 | [1],[2] | |||||||
Gulf Power [Member] | Retiree benefit plans [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 147,625,000 | [1],[4] | 68,296,000 | [1],[4] | 147,625,000 | [1],[4] | 147,625,000 | [1],[4] | 68,296,000 | [1],[4] | 147,625,000 | [1],[4] | 68,296,000 | [1],[4] | |||||||
Gulf Power [Member] | Fuel Expense [Member] | Southern Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 1,700,000 | 800,000 | 2,600,000 | ||||||||||||||||||
Gulf Power [Member] | Purchased Power [Member] | Southern Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 1,800,000 | 14,200,000 | 14,700,000 | ||||||||||||||||||
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Other Regulatory Assets Deferred | 6,100,000 | 0 | 6,100,000 | 6,100,000 | 0 | 6,100,000 | 0 | ||||||||||||||
Gulf Power [Member] | Monitoring Costs [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 11,000,000 | ||||||||||||||||||||
Alabama Power [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Number of Units for which Outage Operations and Maintenance Expenses Accrued | 2 | ||||||||||||||||||||
Period Over which Deferred Costs are Being Amortized to Nuclear Operations and Maintenance Expenses | 18 months | ||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 311,000,000 | ||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 14.00% | 14.00% | 14.00% | 14.00% | |||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Maximum revenue from a single customer or industry | 10.00% | ||||||||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | ||||||||||||||||||||
Income Tax Matters [Abstract] | |||||||||||||||||||||
Amortization of deferred investment tax credits | 8,000,000 | 8,000,000 | 8,000,000 | ||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 8,522,000,000 | 8,114,000,000 | 8,522,000,000 | 8,522,000,000 | 8,114,000,000 | 8,522,000,000 | 8,114,000,000 | ||||||||||||||
Regulatory liabilities amortized | 120,000,000 | ||||||||||||||||||||
Plant acquisition adjustment | 12,000,000 | 12,000,000 | 12,000,000 | 12,000,000 | 12,000,000 | 12,000,000 | 12,000,000 | ||||||||||||||
Decommissioning | |||||||||||||||||||||
Decommissioning Fund Investments Net Of Foreign Currency | 754,000,000 | 713,000,000 | 754,000,000 | 754,000,000 | 713,000,000 | 754,000,000 | 713,000,000 | ||||||||||||||
Investment securities in the Funds | 756,000,000 | 714,000,000 | 756,000,000 | 756,000,000 | 714,000,000 | 756,000,000 | 714,000,000 | ||||||||||||||
Proceeds from sale of securities held in external trust funds | 244,000,000 | 279,000,000 | 193,000,000 | ||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 54,000,000 | 120,000,000 | 70,000,000 | ||||||||||||||||||
Significant assumption of inflation rate used to determine the costs for rate making | 4.50% | ||||||||||||||||||||
Significant assumption of trust earnings rate used to determine the costs for rate making | 7.00% | ||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | |||||||||||||||||||||
Composite rate used to determine allowance for funds used during construction | 8.80% | 9.10% | 9.40% | 8.80% | 8.80% | 9.10% | 8.80% | 9.10% | |||||||||||||
AFUDC, net of income taxes | 7.90% | 5.40% | 3.30% | ||||||||||||||||||
Cash payments for interest totaled | 231,000,000 | 243,000,000 | 273,000,000 | ||||||||||||||||||
Net of amounts capitalized | 18,000,000 | 11,000,000 | 7,000,000 | ||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Maximum total rate NDR charge per month, non-residential customer account | 10 | 10 | 10 | 10 | |||||||||||||||||
Maximum total rate NDR charge per month, residential customer account | 5 | 5 | 5 | 5 | |||||||||||||||||
Old Natural Disaster Reserve Authorized Limit | 75,000,000 | 75,000,000 | 75,000,000 | 75,000,000 | |||||||||||||||||
Net Regulatory Assets | 738,000,000 | 92,000,000 | 738,000,000 | 738,000,000 | 92,000,000 | 738,000,000 | 92,000,000 | ||||||||||||||
Other Regulatory Assets Current | 84,000,000 | 54,000,000 | 84,000,000 | 84,000,000 | 54,000,000 | 84,000,000 | 54,000,000 | ||||||||||||||
Other Regulatory Assets Deferred | 1,063,000,000 | 645,000,000 | 1,063,000,000 | 1,063,000,000 | 645,000,000 | 1,063,000,000 | 645,000,000 | ||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Other Cost of Removal Obligations | 744,000,000 | 828,000,000 | 744,000,000 | 744,000,000 | 828,000,000 | 744,000,000 | 828,000,000 | ||||||||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||||||||||||||||||||
Medicare Drug Subsidy Obligation Related To Subsidiary | 18,000,000 | 20,000,000 | 18,000,000 | 18,000,000 | 20,000,000 | 18,000,000 | 20,000,000 | ||||||||||||||
Amortization Period for Regulatory Deferrals | 5 years | ||||||||||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | 49,000,000 | 32,000,000 | 19,000,000 | ||||||||||||||||||
Alabama Power [Member] | Maximum [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 50 years | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Life of New Issue | 50 years | ||||||||||||||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by PSCs | 10 years | ||||||||||||||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 15 years | ||||||||||||||||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 15 years | ||||||||||||||||||||
Alabama Power [Member] | SEGCO [Member] | |||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 86.00% | 86.00% | 86.00% | 86.00% | |||||||||||||||||
Alabama Power [Member] | Equity Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 583,000,000 | 566,000,000 | 583,000,000 | 583,000,000 | 566,000,000 | 583,000,000 | 566,000,000 | ||||||||||||||
Alabama Power [Member] | Debt Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 163,000,000 | 131,000,000 | 163,000,000 | 163,000,000 | 131,000,000 | 163,000,000 | 131,000,000 | ||||||||||||||
Alabama Power [Member] | Other Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 8,000,000 | 16,000,000 | 8,000,000 | 8,000,000 | 16,000,000 | 8,000,000 | 16,000,000 | ||||||||||||||
Alabama Power [Member] | Securities Held in Funds [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 85,000,000 | 50,000,000 | |||||||||||||||||||
Alabama Power [Member] | Securities Held in Funds [Member] | Realized Gain [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 2,000,000 | 5,000,000 | 4,000,000 | ||||||||||||||||||
Alabama Power [Member] | Securities Held in Funds [Member] | Unrealized Gain [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 19,000,000 | ||||||||||||||||||||
Alabama Power [Member] | Utility Plant in Service [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.30% | 3.20% | 3.20% | ||||||||||||||||||
Alabama Power [Member] | Southern Company Services, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 400,000,000 | 340,000,000 | 340,000,000 | ||||||||||||||||||
Alabama Power [Member] | Southern Nuclear Operating Company, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 234,000,000 | 211,000,000 | 218,000,000 | ||||||||||||||||||
Alabama Power [Member] | Gulf Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Long-term Purchase Commitment, Amount | 85,000,000 | ||||||||||||||||||||
Long-Term Purchase Commitment, Amount Current Year | 29,000,000 | ||||||||||||||||||||
Long-term Purchase Commitment, Period Over Which Costs Are Expected to Be Recovered | 2023 | ||||||||||||||||||||
Alabama Power [Member] | Recoverable Vacation Pay [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 65,000,000 | [1],[2] | 63,000,000 | [1],[2] | 65,000,000 | [1],[2] | 65,000,000 | [1],[2] | 63,000,000 | [1],[2] | 65,000,000 | [1],[2] | 63,000,000 | [1],[2] | |||||||
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Other Regulatory Assets Deferred | 68,000,000 | 6,000,000 | 68,000,000 | 68,000,000 | 6,000,000 | 68,000,000 | 6,000,000 | ||||||||||||||
Alabama Power [Member] | Plant Farley [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Estimated cost of decommissioning completion year | 2076 | ||||||||||||||||||||
Alabama Power [Member] | Monitoring Costs [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 49,000,000 | ||||||||||||||||||||
Alabama Power [Member] | Fuel Purchases [Member] | Mississippi Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 34,000,000 | 27,000,000 | 28,000,000 | ||||||||||||||||||
Alabama Power [Member] | Non-Fuel Expense [Member] | Mississippi Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 13,000,000 | 13,000,000 | 12,000,000 | ||||||||||||||||||
Georgia Power [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 390,000,000 | ||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Deferred capacity expense | 167,000,000 | 162,000,000 | 169,000,000 | 167,000,000 | 167,000,000 | 162,000,000 | 167,000,000 | 162,000,000 | |||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Maximum revenue from a single customer or industry | 10.00% | ||||||||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | ||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Refueling cycles for Alabama Power and Georgia Power, minimum months | 18 months | ||||||||||||||||||||
Refueling cycles for Alabama Power and Georgia Power, maximum months | 24 months | ||||||||||||||||||||
Income Tax Matters [Abstract] | |||||||||||||||||||||
Amortization of deferred investment tax credits | 10,000,000 | 5,000,000 | 13,000,000 | ||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 2.70% | 3.00% | 2.90% | ||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 11,222,000,000 | 10,970,000,000 | 11,222,000,000 | 11,222,000,000 | 10,970,000,000 | 11,222,000,000 | 10,970,000,000 | ||||||||||||||
Regulatory liabilities amortized | 31,000,000 | 14,000,000 | 31,000,000 | ||||||||||||||||||
Amortization period of other cost of removal obligations | 2 years | 3 years | 3 years | ||||||||||||||||||
Plant acquisition adjustment | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | ||||||||||||||
Decommissioning | |||||||||||||||||||||
Fair market value of fund's securities on loan under the Funds' managers' securities lending program | 51,000,000 | 32,000,000 | 51,000,000 | 51,000,000 | 32,000,000 | 51,000,000 | 32,000,000 | ||||||||||||||
Fair value of collateral received | 52,000,000 | 33,000,000 | 52,000,000 | 52,000,000 | 33,000,000 | 52,000,000 | 33,000,000 | ||||||||||||||
Decommissioning Fund Investments Net Of Foreign Currency | 789,000,000 | 751,000,000 | 789,000,000 | 789,000,000 | 751,000,000 | 789,000,000 | 751,000,000 | ||||||||||||||
Investment securities in the Funds | 789,000,000 | 751,000,000 | 789,000,000 | 789,000,000 | 751,000,000 | 789,000,000 | 751,000,000 | ||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 44,000,000 | 61,000,000 | 67,000,000 | ||||||||||||||||||
Significant assumption of inflation rate used to determine the costs for rate making | 2.40% | ||||||||||||||||||||
Significant assumption of trust earnings rate used to determine the costs for rate making | 4.40% | ||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | |||||||||||||||||||||
Composite rate used to determine allowance for funds used during construction | 5.60% | 5.30% | 6.80% | 5.60% | 5.60% | 5.30% | 5.60% | 5.30% | |||||||||||||
AFUDC capitalized | 62,000,000 | 44,000,000 | 75,000,000 | ||||||||||||||||||
AFUDC, net of income taxes | 4.60% | 3.30% | 5.70% | ||||||||||||||||||
Cash payments for interest totaled | 319,000,000 | 344,000,000 | 337,000,000 | ||||||||||||||||||
Net of amounts capitalized | 18,000,000 | 14,000,000 | 21,000,000 | ||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation | 22,000,000 | 22,000,000 | 22,000,000 | 22,000,000 | |||||||||||||||||
Net Regulatory Assets | 2,529,000,000 | 1,886,000,000 | 2,529,000,000 | 2,529,000,000 | 1,886,000,000 | 2,529,000,000 | 1,886,000,000 | ||||||||||||||
Other Regulatory Assets Current | 136,000,000 | 106,000,000 | 136,000,000 | 136,000,000 | 106,000,000 | 136,000,000 | 106,000,000 | ||||||||||||||
Other Regulatory Assets Deferred | 1,753,000,000 | 1,113,000,000 | 1,753,000,000 | 1,753,000,000 | 1,113,000,000 | 1,753,000,000 | 1,113,000,000 | ||||||||||||||
Accrual Under Alternate Rate Plan | 30,000,000 | ||||||||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Other Cost of Removal Obligations | 46,000,000 | 43,000,000 | 46,000,000 | 46,000,000 | 43,000,000 | 46,000,000 | 43,000,000 | ||||||||||||||
Previously Recorded Asset Retirement Obligation | 500,000,000 | ||||||||||||||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||||||||||||||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 13 years | ||||||||||||||||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 8 years | ||||||||||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | 45,000,000 | 30,000,000 | 53,000,000 | ||||||||||||||||||
Georgia Power [Member] | Unrealized Losses [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Increase (Decrease) in fair value of securities related to nuclear decommissioning | 34,000,000 | 25,000,000 | |||||||||||||||||||
Georgia Power [Member] | Maximum [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Life of Related Property Over which Deferred Income Tax Liabilities are Amortized | 70 years | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Life of New Issue | 38 years | ||||||||||||||||||||
Recovered and Amortized as Approved by Appropriate State PSCs | 10 years | ||||||||||||||||||||
Georgia Power [Member] | Plant Scherer Unit 3 [Member] | |||||||||||||||||||||
Jointly Owned Utility Plant Interests [Abstract] | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 75.00% | 75.00% | 75.00% | 75.00% | |||||||||||||||||
Georgia Power [Member] | Plant Hatch [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Estimated cost of decommissioning completion year | 2068 | ||||||||||||||||||||
Amount expensed for rate making purpose | 4,000,000 | ||||||||||||||||||||
Georgia Power [Member] | Plant Vogtle [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Estimated cost of decommissioning completion year | 2072 | ||||||||||||||||||||
Amount expensed for rate making purpose | 2,000,000 | ||||||||||||||||||||
Georgia Power [Member] | Securities Investment [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 669,000,000 | 705,000,000 | 850,000,000 | 669,000,000 | 669,000,000 | 705,000,000 | 669,000,000 | 705,000,000 | |||||||||||||
Georgia Power [Member] | Equity Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 303,000,000 | 330,000,000 | 303,000,000 | 303,000,000 | 330,000,000 | 303,000,000 | 330,000,000 | ||||||||||||||
Georgia Power [Member] | Debt Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 475,000,000 | 397,000,000 | 475,000,000 | 475,000,000 | 397,000,000 | 475,000,000 | 397,000,000 | ||||||||||||||
Georgia Power [Member] | Other Securities [Member] | |||||||||||||||||||||
Decommissioning | |||||||||||||||||||||
Investment securities in the Funds | 11,000,000 | 24,000,000 | 11,000,000 | 11,000,000 | 24,000,000 | 11,000,000 | 24,000,000 | ||||||||||||||
Georgia Power [Member] | Southern Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 144,000,000 | 136,000,000 | 147,000,000 | ||||||||||||||||||
Prepaid capacity expenses | 15,000,000 | 15,000,000 | 15,000,000 | 15,000,000 | 15,000,000 | 15,000,000 | 15,000,000 | ||||||||||||||
Georgia Power [Member] | Southern Company Services, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 555,000,000 | 504,000,000 | 540,000,000 | ||||||||||||||||||
Georgia Power [Member] | Southern Nuclear Operating Company, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 643,000,000 | 555,000,000 | 574,000,000 | ||||||||||||||||||
Georgia Power [Member] | Gulf Power [Member] | Plant Scherer Unit 3 [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Gulf Power agreement, percentage reimbursement of non-fuel expenses | 25.00% | 25.00% | 25.00% | 25.00% | |||||||||||||||||
Georgia Power [Member] | Other regulatory assets current [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Environmental Regulatory Assets | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | |||||||||||||||||
Georgia Power [Member] | Other regulatory assets deferred [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Environmental Regulatory Assets | 14,000,000 | 14,000,000 | 14,000,000 | 14,000,000 | |||||||||||||||||
Georgia Power [Member] | Recoverable Vacation Pay [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 91,000,000 | [2] | 88,000,000 | [2] | 91,000,000 | [2] | 91,000,000 | [2] | 88,000,000 | [2] | 91,000,000 | [2] | 88,000,000 | [2] | |||||||
Georgia Power [Member] | Retiree benefit plans [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 1,325,000,000 | [5] | 691,000,000 | [5] | 1,325,000,000 | [5] | 1,325,000,000 | [5] | 691,000,000 | [5] | 1,325,000,000 | [5] | 691,000,000 | [5] | |||||||
Georgia Power [Member] | Property damage reserves [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Regulatory asset | 98,000,000 | 37,000,000 | 98,000,000 | 98,000,000 | 37,000,000 | 98,000,000 | 37,000,000 | ||||||||||||||
Other Regulatory Assets Current | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | ||||||||||||||
Other Regulatory Assets Deferred | 68,000,000 | 7,000,000 | 68,000,000 | 68,000,000 | 7,000,000 | 68,000,000 | 7,000,000 | ||||||||||||||
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Other Regulatory Assets Deferred | 213,000,000 | 69,000,000 | 213,000,000 | 213,000,000 | 69,000,000 | 213,000,000 | 69,000,000 | ||||||||||||||
Georgia Power [Member] | Monitoring Costs [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 62,000,000 | ||||||||||||||||||||
Georgia Power [Member] | Non-Fuel Expense [Member] | Gulf Power [Member] | Plant Scherer Unit 3 [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Gulf Power agreement, reimbursement of non-fuel expenses | 9,000,000 | 10,000,000 | 7,000,000 | ||||||||||||||||||
Alabama Power and Georgia Power [Member] | |||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Refueling cycles for Alabama Power and Georgia Power, minimum months | 18 months | ||||||||||||||||||||
Refueling cycles for Alabama Power and Georgia Power, maximum months | 24 months | ||||||||||||||||||||
Mississippi Power [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 64,000,000 | ||||||||||||||||||||
Revenues [Abstract] | |||||||||||||||||||||
Percentage Of Wholesale Customers To Operating Revenue | 21.90% | ||||||||||||||||||||
Period Of Contract Cancellation Notices Of Wholesale Customers | 10 years | ||||||||||||||||||||
Maximum revenue from a single customer or industry | 10.00% | ||||||||||||||||||||
Maximum percentage of uncollectible accounts | 1.00% | ||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 10.13% | 9.93% | 9.97% | 10.13% | 7.13% | 10.13% | 9.93% | 10.13% | 9.93% | ||||||||||||
Income Tax Matters [Abstract] | |||||||||||||||||||||
Amortization of deferred investment tax credits | 1,400,000 | 1,200,000 | 1,200,000 | ||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Depreciation of cost of utility plant in service, composite straight-line rate | 3.30% | 3.40% | 3.50% | ||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,172,715,000 | 1,095,352,000 | 1,172,715,000 | 1,172,715,000 | 1,095,352,000 | 1,172,715,000 | 1,095,352,000 | ||||||||||||||
Plant acquisition adjustment | 81,412,000 | 81,412,000 | 81,412,000 | 81,412,000 | 81,412,000 | 81,412,000 | 81,412,000 | ||||||||||||||
Amortization period of regulatory assets and liabilities | 50 years | ||||||||||||||||||||
Allowance for Funds Used During Construction and Interest Capitalized | |||||||||||||||||||||
Composite rate used to determine allowance for funds used during construction | 6.91% | 6.89% | 7.04% | 6.91% | 6.91% | 6.89% | 6.91% | 6.89% | |||||||||||||
Cash payments for interest totaled | 6,992,000 | 20,285,000 | 32,589,000 | ||||||||||||||||||
Net of amounts capitalized | 68,679,000 | 54,118,000 | 32,816,000 | ||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 171,764,000 | 66,604,000 | 171,764,000 | 171,764,000 | 66,604,000 | 171,764,000 | 66,604,000 | ||||||||||||||
Threshold above which actual damages are charged to the reserve | 50,000 | 50,000 | 50,000 | 50,000 | |||||||||||||||||
Retail accrual per annual SRR rate | 3,300,000 | 3,200,000 | 3,500,000 | 3,300,000 | 3,300,000 | 3,200,000 | 3,300,000 | 3,200,000 | |||||||||||||
Wholesale accrual per annual SRR rate | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | |||||||||||||
Other Regulatory Assets Current | 72,840,000 | 48,583,000 | 72,840,000 | 72,840,000 | 48,583,000 | 72,840,000 | 48,583,000 | ||||||||||||||
Other Regulatory Assets Deferred | 385,410,000 | 200,620,000 | 385,410,000 | 385,410,000 | 200,620,000 | 385,410,000 | 200,620,000 | ||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||
Original Maturities of Temporary Cash Investments | 90 days | ||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Variable Interest Entity, Consolidated, Carrying Amount, Assets | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | 21,000,000 | |||||||||||||
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities | 23,600,000 | 22,700,000 | 21,800,000 | 23,600,000 | 23,600,000 | 22,700,000 | 23,600,000 | 22,700,000 | |||||||||||||
Other Cost of Removal Obligations | 165,999,000 | 156,683,000 | 165,999,000 | 165,999,000 | 156,683,000 | 165,999,000 | 156,683,000 | ||||||||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Average Remaining Service Period | 14 years | ||||||||||||||||||||
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity | 136,436,000 | 121,629,000 | 64,793,000 | ||||||||||||||||||
Mississippi Power [Member] | Mississippi Public Service Commission [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Period To Agree On System Restoration Rider | 3 years | ||||||||||||||||||||
Mississippi Power [Member] | Southern Company Services, Inc. [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 259,000,000 | 205,000,000 | 212,700,000 | ||||||||||||||||||
Mississippi Power [Member] | Gulf Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 30,500,000 | 16,500,000 | 21,200,000 | ||||||||||||||||||
Mississippi Power [Member] | Property tax [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Amortization period of regulatory assets and liabilities | 12 months | ||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 27,680,000 | [6] | 31,206,000 | [6] | 27,680,000 | [6] | 27,680,000 | [6] | 31,206,000 | [6] | 27,680,000 | [6] | 31,206,000 | [6] | |||||||
Mississippi Power [Member] | Recoverable Vacation Pay [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 11,172,000 | [1],[2] | 10,214,000 | [1],[2] | 11,172,000 | [1],[2] | 11,172,000 | [1],[2] | 10,214,000 | [1],[2] | 11,172,000 | [1],[2] | 10,214,000 | [1],[2] | |||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Amortization of Regulatory Asset, Vacation Pay | 1 year | ||||||||||||||||||||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 16,334,000 | 2,116,000 | 16,334,000 | 16,334,000 | 2,116,000 | 16,334,000 | 2,116,000 | ||||||||||||||
Other Regulatory Assets Deferred | 18,345,000 | 5,227,000 | 18,345,000 | 18,345,000 | 5,227,000 | 18,345,000 | 5,227,000 | ||||||||||||||
Mississippi Power [Member] | Plant Daniel Units 3 and 4 [Member] | |||||||||||||||||||||
Depreciation and Amortization | |||||||||||||||||||||
Fair value adjustment at date of purchase | 76,100,000 | ||||||||||||||||||||
Amortization period of regulatory assets and liabilities | 10 years | ||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Net Regulatory Assets | 23,013,000 | [7] | 18,821,000 | [7] | 23,013,000 | [7] | 23,013,000 | [7] | 18,821,000 | [7] | 23,013,000 | [7] | 18,821,000 | [7] | |||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Recovery and Amortization Periods for Regulatory Assets Liabilities Approved by PSCs | 10 years | ||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | |||||||||||||||||||||
Government Grants [Abstract] | |||||||||||||||||||||
Grants expected to be received from Department of Energy | 25,000,000 | 25,000,000 | 25,000,000 | 25,000,000 | 270,000,000 | ||||||||||||||||
Grants received from Department of Energy | 245,300,000 | ||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Regulatory asset | 147,700,000 | 147,700,000 | 147,700,000 | 147,700,000 | |||||||||||||||||
Mississippi Power [Member] | Monitoring Costs [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Accrued Capping, Closure, Post-closure and Environmental Costs | 12,000,000 | ||||||||||||||||||||
Mississippi Power [Member] | Fuel Purchases [Member] | Alabama Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 34,500,000 | 27,100,000 | 28,100,000 | ||||||||||||||||||
Mississippi Power [Member] | Non-Fuel Expense [Member] | Alabama Power [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 13,400,000 | 12,500,000 | 11,700,000 | ||||||||||||||||||
Mississippi Power [Member] | Storm Assistance [Member] | Traditional Operating Companies [Member] | |||||||||||||||||||||
Affiliate Transactions [Abstract] | |||||||||||||||||||||
Related Party Transaction, Amounts of Transaction | 2,000,000 | ||||||||||||||||||||
Traditional Operating Companies [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Accrued reserves | 40,000,000 | 28,000,000 | 40,000,000 | 40,000,000 | 28,000,000 | 40,000,000 | 28,000,000 | ||||||||||||||
Capital Lease Obligations [Member] | |||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Non-cash property additions recognized | 25,000,000 | 107,000,000 | 14,000,000 | ||||||||||||||||||
Capital Lease Obligations [Member] | Alabama Power [Member] | |||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 6.90% | 6.90% | 6.90% | 6.90% | 6.90% | 6.90% | 6.90% | ||||||||||||||
Capital Lease Obligations [Member] | Georgia Power [Member] | |||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.90% | 7.90% | 7.90% | 7.90% | 7.90% | 7.90% | 7.90% | ||||||||||||||
Capital Lease Obligations [Member] | Mississippi Power [Member] | |||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.90% | ||||||||||||||||||||
Solar Gen 2 Imperial Valley, LLC [Member] | Southern Power [Member] | |||||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||||
Payments to Acquire Businesses, Gross | 504,700,000 | [8],[9] | 504,700,000 | ||||||||||||||||||
Life Output Of Plant | 25 years | [8],[9] | 25 years | ||||||||||||||||||
Power of Solar Polycrystalline Silicon Facility | 150 | [8],[9] | 150 | [8],[9] | 150 | [8],[9] | 150 | 150 | [8],[9] | ||||||||||||
Settlement Agreement [Member] | Gulf Power [Member] | |||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Other Cost of Removal Obligations | 62,500,000 | 62,500,000 | 62,500,000 | 62,500,000 | |||||||||||||||||
Nominal Dollar Basis [Member] | |||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Previously Recorded Asset Retirement Obligation | 468,000,000 | ||||||||||||||||||||
Nominal Dollar Basis [Member] | Gulf Power [Member] | |||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Previously Recorded Asset Retirement Obligation | 11,000,000 | ||||||||||||||||||||
Nominal Dollar Basis [Member] | Georgia Power [Member] | |||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Previously Recorded Asset Retirement Obligation | 458,000,000 | ||||||||||||||||||||
Environmental Remediation Reserve [Member] | Georgia Power [Member] | |||||||||||||||||||||
Reserves and Recoveries | |||||||||||||||||||||
Costs recovered annually under rate plan | 3,000,000 | 2,000,000 | |||||||||||||||||||
Retail [Member] | |||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Proposed Property Damage Reserve | 60,700,000 | 60,700,000 | 60,700,000 | 60,700,000 | |||||||||||||||||
Wholesale [Member] | |||||||||||||||||||||
Variable Interest Entities [Abstract] | |||||||||||||||||||||
Proposed Property Damage Reserve | $1,000,000 | $1,000,000 | $1,000,000 | $1,000,000 | |||||||||||||||||
[1] | Not earning a return as offset in rate base by a corresponding asset or liability. | ||||||||||||||||||||
[2] | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | ||||||||||||||||||||
[3] | Recovered and amortized over the average remaining service period which may range up to 15 years. See Note 2 for additional information. | ||||||||||||||||||||
[4] | Recovered and amortized over the average remaining service period which may range up to 14 years. See NoteB 2 for additional information. | ||||||||||||||||||||
[5] | Recovered and amortized over the average remaining service period which may range up to 13 years. See Note 2 for additional information. | ||||||||||||||||||||
[6] | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. | ||||||||||||||||||||
[7] | Deferred and amortized over a 10-year period beginning October 2021, as approved by the Mississippi PSC for the difference between the revenue requirement under the purchase option and the revenue requirement assuming operating lease accounting treatment for the extended term. | ||||||||||||||||||||
[8] | Reflects Southern Power's portion of the purchase price. | ||||||||||||||||||||
[9] | This acquisition was made by Southern Power through its subsidiaries Southern Renewable Partnerships, LLC and SG2 Holdings, LLC. SG2 Holdings, LLC is jointly-owned by Southern Power and First Solar, Inc. |
Retirement_Benefits_Actuarial_
Retirement Benefits - Actuarial Assumptions 1 (Details) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Discount rate: | ||||
Annual salary increase | 3.59% | 3.59% | 3.59% | 3.84% |
Pension Plans [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.17% | 5.02% | 4.26% | 4.98% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% | |
Other Postretirement Benefits [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.04% | 4.85% | 4.05% | 4.88% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 7.15% | 7.13% | 7.29% | |
Alabama Power [Member] | ||||
Discount rate: | ||||
Annual salary increase | 3.59% | 3.59% | 3.59% | 3.84% |
Alabama Power [Member] | Pension Plans [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% | 4.98% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.04% | 4.86% | 4.06% | 4.88% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 7.34% | 7.36% | 7.19% | |
Georgia Power [Member] | ||||
Discount rate: | ||||
Annual salary increase | 3.59% | 3.59% | 3.59% | 3.84% |
Georgia Power [Member] | Pension Plans [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% | 4.98% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.03% | 4.85% | 4.04% | 4.87% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 6.75% | 6.74% | 7.24% | |
Gulf Power [Member] | ||||
Discount rate: | ||||
Annual salary increase | 3.59% | 3.59% | 3.59% | 3.84% |
Gulf Power [Member] | Pension Plans [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% | 4.98% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.04% | 4.86% | 4.06% | 4.88% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 8.08% | 8.04% | 8.02% | |
Mississippi Power [Member] | ||||
Discount rate: | ||||
Annual salary increase | 3.59% | 3.59% | 3.59% | 3.84% |
Mississippi Power [Member] | Pension Plans [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.17% | 5.01% | 4.26% | 4.98% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 8.20% | 8.20% | 8.20% | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||||
Discount rate: | ||||
Discount rate on net periodic benefit costs | 4.03% | 4.85% | 4.04% | 4.87% |
Long-term return on plan assets: | ||||
Long-term return on plan assets on net periodic benefit costs | 7.30% | 7.04% | 6.96% |
Retirement_Benefits_Actuarial_1
Retirement Benefits - Actuarial Assumptions 2 (Details) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | $140,000 |
1 Percent decrease on benefit obligation | -117,000 |
1 Percent increase on service and interest costs | 6,000 |
1 Percent decrease on service and interest costs | -5,000 |
Alabama Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 34,000 |
1 Percent decrease on benefit obligation | -29,000 |
1 Percent increase on service and interest costs | 1,000 |
1 Percent decrease on service and interest costs | -1,000 |
Georgia Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 69,000 |
1 Percent decrease on benefit obligation | -58,000 |
1 Percent increase on service and interest costs | 3,000 |
1 Percent decrease on service and interest costs | -2,000 |
Gulf Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 3,934 |
1 Percent decrease on benefit obligation | -3,334 |
1 Percent increase on service and interest costs | 157 |
1 Percent decrease on service and interest costs | -133 |
Mississippi Power [Member] | |
Effect of one percent annual increase or decrease in the assumed medical care cost on APBO and the service and interest cost components | |
1 Percent increase on benefit obligation | 6,241 |
1 Percent decrease on benefit obligation | -5,289 |
1 Percent increase on service and interest costs | 250 |
1 Percent decrease on service and interest costs | ($212) |
Retirement_Benefits_Changes_in
Retirement Benefits - Changes in Projected Benefit Obligations and Fair Value of Plan Assets (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | $8,863,000 | $9,302,000 | |
Service cost | 213,000 | 232,000 | 198,000 |
Interest cost | 435,000 | 389,000 | 393,000 |
Benefits paid | -382,000 | -357,000 | |
Actuarial loss (gain) | 1,780,000 | -703,000 | |
Balance at end of year | 10,909,000 | 8,863,000 | 9,302,000 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 8,733,000 | 7,953,000 | |
Actual return (loss) on plan assets | 797,000 | 1,098,000 | |
Employer contributions | 542,000 | 39,000 | |
Fair value of plan assets at end of year | 9,690,000 | 8,733,000 | 7,953,000 |
Accrued liability | -1,219,000 | -130,000 | |
Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 1,682,000 | 1,872,000 | |
Service cost | 21,000 | 24,000 | 21,000 |
Interest cost | 79,000 | 74,000 | 85,000 |
Benefits paid | -102,000 | -94,000 | |
Plan amendments | -2,000 | 0 | |
Actuarial loss (gain) | 300,000 | -200,000 | |
Retiree drug subsidy | 8,000 | 6,000 | |
Balance at end of year | 1,986,000 | 1,682,000 | 1,872,000 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 901,000 | 821,000 | |
Actual return (loss) on plan assets | 54,000 | 129,000 | |
Employer contributions | 39,000 | 39,000 | |
Benefits paid, net of drug subsidy | -94,000 | -88,000 | |
Fair value of plan assets at end of year | 900,000 | 901,000 | 821,000 |
Accrued liability | -1,086,000 | -781,000 | |
Alabama Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 2,112,000 | 2,218,000 | |
Service cost | 48,000 | 52,000 | 44,000 |
Interest cost | 103,000 | 93,000 | 94,000 |
Benefits paid | -100,000 | -93,000 | |
Actuarial loss (gain) | 429,000 | -158,000 | |
Balance at end of year | 2,592,000 | 2,112,000 | 2,218,000 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 2,278,000 | 2,077,000 | |
Actual return (loss) on plan assets | 207,000 | 285,000 | |
Employer contributions | 11,000 | 9,000 | |
Fair value of plan assets at end of year | 2,396,000 | 2,278,000 | 2,077,000 |
Accrued liability | -196,000 | 166,000 | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 431,000 | 490,000 | |
Service cost | 5,000 | 6,000 | 5,000 |
Interest cost | 20,000 | 19,000 | 22,000 |
Benefits paid | -27,000 | -24,000 | |
Actuarial loss (gain) | 71,000 | -62,000 | |
Retiree drug subsidy | 3,000 | 2,000 | |
Balance at end of year | 503,000 | 431,000 | 490,000 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 389,000 | 343,000 | |
Actual return (loss) on plan assets | 23,000 | 61,000 | |
Employer contributions | 4,000 | 7,000 | |
Benefits paid, net of drug subsidy | -24,000 | -22,000 | |
Fair value of plan assets at end of year | 392,000 | 389,000 | 343,000 |
Accrued liability | -111,000 | -42,000 | |
Georgia Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 3,116,000 | 3,312,000 | |
Service cost | 62,000 | 69,000 | 60,000 |
Interest cost | 153,000 | 138,000 | 141,000 |
Benefits paid | -149,000 | -141,000 | |
Actuarial loss (gain) | 599,000 | -262,000 | |
Balance at end of year | 3,781,000 | 3,116,000 | 3,312,000 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 3,085,000 | 2,827,000 | |
Actual return (loss) on plan assets | 285,000 | 387,000 | |
Employer contributions | 162,000 | 12,000 | |
Fair value of plan assets at end of year | 3,383,000 | 3,085,000 | 2,827,000 |
Accrued liability | -398,000 | -31,000 | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 723,000 | 800,000 | |
Service cost | 6,000 | 7,000 | 7,000 |
Interest cost | 34,000 | 31,000 | 37,000 |
Benefits paid | -44,000 | -45,000 | |
Actuarial loss (gain) | 142,000 | -73,000 | |
Retiree drug subsidy | 3,000 | 3,000 | |
Balance at end of year | 864,000 | 723,000 | 800,000 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 407,000 | 382,000 | |
Actual return (loss) on plan assets | 21,000 | 56,000 | |
Employer contributions | 8,000 | 11,000 | |
Benefits paid, net of drug subsidy | -41,000 | -42,000 | |
Fair value of plan assets at end of year | 395,000 | 407,000 | 382,000 |
Accrued liability | -469,000 | -316,000 | |
Gulf Power [Member] | |||
Change in benefit obligation | |||
Service cost | 10,181 | 11,128 | 9,101 |
Interest cost | 19,433 | 17,321 | 17,199 |
Gulf Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 395,328 | 413,501 | |
Service cost | 10,181 | 11,128 | |
Interest cost | 19,433 | 17,321 | |
Benefits paid | -15,635 | -14,831 | |
Actuarial loss (gain) | 81,254 | -31,791 | |
Balance at end of year | 490,561 | 395,328 | |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 385,639 | 350,260 | |
Actual return (loss) on plan assets | 33,512 | 49,076 | |
Employer contributions | 31,251 | 1,134 | |
Fair value of plan assets at end of year | 434,767 | 385,639 | |
Accrued liability | -55,794 | -9,689 | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 68,579 | 75,395 | |
Service cost | 1,163 | 1,355 | 1,167 |
Interest cost | 3,235 | 2,982 | 3,367 |
Benefits paid | -4,061 | -3,583 | |
Plan amendments | -2,089 | 0 | |
Actuarial loss (gain) | 11,317 | -7,900 | |
Retiree drug subsidy | 357 | 330 | |
Balance at end of year | 78,501 | 68,579 | 75,395 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 17,474 | 16,227 | |
Actual return (loss) on plan assets | 1,578 | 2,119 | |
Employer contributions | 2,846 | 2,381 | |
Benefits paid, net of drug subsidy | -3,704 | -3,253 | |
Fair value of plan assets at end of year | 18,194 | 17,474 | 16,227 |
Accrued liability | -60,307 | -51,105 | |
Mississippi Power [Member] | |||
Change in benefit obligation | |||
Service cost | 10,123 | 11,067 | 9,416 |
Interest cost | 20,093 | 18,062 | 18,019 |
Change in plan assets | |||
Employer contributions | 4,600 | 4,100 | 3,900 |
Mississippi Power [Member] | Pension Plans [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 409,395 | 432,553 | |
Service cost | 10,123 | 11,067 | |
Interest cost | 20,093 | 18,062 | |
Benefits paid | -17,499 | -16,207 | |
Actuarial loss (gain) | 90,735 | -36,080 | |
Balance at end of year | 512,847 | 409,395 | |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 387,403 | 351,749 | |
Actual return (loss) on plan assets | 40,051 | 49,431 | |
Employer contributions | 35,526 | 2,430 | |
Fair value of plan assets at end of year | 445,481 | 387,403 | |
Accrued liability | -67,366 | -21,992 | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Change in benefit obligation | |||
Benefit obligation at beginning of year | 80,940 | 91,783 | |
Service cost | 1,025 | 1,151 | 1,038 |
Interest cost | 3,812 | 3,619 | 4,155 |
Benefits paid | -4,887 | -4,080 | |
Actuarial loss (gain) | 14,259 | -11,959 | |
Retiree drug subsidy | 506 | 426 | |
Balance at end of year | 95,655 | 80,940 | 91,783 |
Change in plan assets | |||
Fair value of plan assets at beginning of year | 23,277 | 21,990 | |
Actual return (loss) on plan assets | 1,814 | 2,379 | |
Employer contributions | 3,413 | 2,562 | |
Benefits paid, net of drug subsidy | -4,381 | -3,654 | |
Fair value of plan assets at end of year | 24,123 | 23,277 | 21,990 |
Accrued liability | ($71,532) | ($57,663) |
Retirement_Benefits_Schedule_O
Retirement Benefits - Schedule Of Health Care Cost Trend Rates (Details) (Other Postretirement Benefit Plan [Member]) | 12 Months Ended |
Dec. 31, 2014 | |
Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 9.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.75% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Georgia Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 9.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Georgia Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Georgia Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.75% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Mississippi Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 9.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Mississippi Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Mississippi Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.75% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Alabama Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 9.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Alabama Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Alabama Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.75% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Gulf Power [Member] | Pre Sixty Five [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 9.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Gulf Power [Member] | Post Sixty Five Medical [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.00% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Gulf Power [Member] | Post Sixty Five Prescription [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Initial Cost Trend Rate | 6.75% |
Ultimate Cost Trend Rate | 4.50% |
Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate | 2024 |
Retirement_Benefits_Amounts_Re
Retirement Benefits - Amounts Recognized in Balance Sheets and Amounts in AOCI (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | $0 | $419,000 |
Other regulatory assets, deferred | 4,334,000 | 2,495,000 |
Other current liabilities | -544,000 | -346,000 |
Other regulatory liabilities, deferred | -398,000 | -479,000 |
Employee benefit obligations | -2,432,000 | -1,461,000 |
Accumulated OCI | -128,000 | -75,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Net Regulatory Assets | 4,664,000 | 2,624,000 |
Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 419,000 |
Other regulatory assets, deferred | 3,073,000 | 1,651,000 |
Other current liabilities | -42,000 | -40,000 |
Employee benefit obligations | -1,177,000 | -509,000 |
Accumulated OCI | 134,000 | 64,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 55,000 | 80,000 |
Net (Gain) Loss | 3,152,000 | 1,634,000 |
Prior Service Cost, Estimated | 25,000 | |
Net (Gain) Loss, Estimated | 215,000 | |
Pension Plans [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 4,000 | 5,000 |
Net (Gain) Loss | 130,000 | 59,000 |
Prior Service Cost, Estimated | 1,000 | |
Net (Gain) Loss, Estimated | 9,000 | |
Pension Plans [Member] | Regulatory Assets [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 51,000 | 75,000 |
Net (Gain) Loss | 3,022,000 | 1,575,000 |
Prior Service Cost, Estimated | 24,000 | |
Net (Gain) Loss, Estimated | 206,000 | |
Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 387,000 | 109,000 |
Other current liabilities | -4,000 | -4,000 |
Other regulatory liabilities, deferred | -21,000 | -36,000 |
Employee benefit obligations | -1,082,000 | -777,000 |
Accumulated OCI | 8,000 | 1,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 2,000 | 9,000 |
Net (Gain) Loss | 372,000 | 65,000 |
Prior Service Cost, Estimated | 4,000 | |
Net (Gain) Loss, Estimated | 17,000 | |
Other Postretirement Benefits [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 0 | 0 |
Net (Gain) Loss | 8,000 | 1,000 |
Prior Service Cost, Estimated | 0 | |
Net (Gain) Loss, Estimated | 0 | |
Other Postretirement Benefits [Member] | Regulatory Assets [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 2,000 | 9,000 |
Net (Gain) Loss | 364,000 | 64,000 |
Prior Service Cost, Estimated | 4,000 | |
Net (Gain) Loss, Estimated | 17,000 | |
Alabama Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 276,000 |
Other regulatory assets, deferred | 1,063,000 | 645,000 |
Other current liabilities | -80,000 | -41,000 |
Other regulatory liabilities, deferred | -239,000 | -259,000 |
Employee benefit obligations | -326,000 | -195,000 |
Accumulated OCI | -29,000 | -26,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Net Regulatory Assets | 738,000 | 92,000 |
Alabama Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 276,000 |
Other regulatory assets, deferred | 827,000 | 476,000 |
Other current liabilities | -10,000 | -9,000 |
Employee benefit obligations | -186,000 | -101,000 |
Alabama Power [Member] | Pension Plans [Member] | Regulatory Assets [Member] | ||
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 12,000 | 19,000 |
Net (Gain) Loss | 815,000 | 457,000 |
Prior Service Cost, Estimated | 6,000 | |
Net (Gain) Loss, Estimated | -55,000 | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 68,000 | 6,000 |
Other regulatory liabilities, deferred | -14,000 | -21,000 |
Employee benefit obligations | -111,000 | -42,000 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Regulatory Assets [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 54,000 | -15,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 15,000 | 19,000 |
Net (Gain) Loss | 39,000 | -34,000 |
Prior Service Cost, Estimated | 4,000 | |
Net (Gain) Loss, Estimated | 2,000 | |
Georgia Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 118,000 |
Other regulatory assets, deferred | 1,753,000 | 1,113,000 |
Other current liabilities | -204,000 | -122,000 |
Employee benefit obligations | -903,000 | -542,000 |
Accumulated OCI | -8,000 | -5,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Net Regulatory Assets | 2,529,000 | 1,886,000 |
Georgia Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 118,000 |
Other regulatory assets, deferred | 1,102,000 | 610,000 |
Other current liabilities | -12,000 | -12,000 |
Employee benefit obligations | -386,000 | -137,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 17,000 | 26,000 |
Net (Gain) Loss | 1,085,000 | 584,000 |
Prior Service Cost, Estimated | 9,000 | |
Net (Gain) Loss, Estimated | 76,000 | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 213,000 | 69,000 |
Employee benefit obligations | -469,000 | -316,000 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | -5,000 | -4,000 |
Net (Gain) Loss | 218,000 | 73,000 |
Prior Service Cost, Estimated | 0 | |
Net (Gain) Loss, Estimated | 11,000 | |
Gulf Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 11,533 |
Other regulatory assets, deferred | 416,028 | 340,415 |
Other current liabilities | -22,386 | -22,972 |
Other regulatory liabilities, deferred | -48,556 | -56,051 |
Employee benefit obligations | -120,752 | -76,338 |
Accumulated OCI | -737 | -1,109 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Net Regulatory Assets | 319,644 | 160,224 |
Gulf Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 11,533 |
Other regulatory assets, deferred | 145,815 | 75,280 |
Other current liabilities | -1,307 | -1,183 |
Employee benefit obligations | -54,487 | -20,039 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 3,286 | 4,401 |
Net (Gain) Loss | 142,529 | 70,879 |
Prior Service Cost, Estimated | 1,115 | |
Net (Gain) Loss, Estimated | 9,281 | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 6,100 | 0 |
Other current liabilities | -639 | -687 |
Other regulatory liabilities, deferred | -4,290 | -6,984 |
Employee benefit obligations | -59,668 | -50,418 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Regulatory Assets [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 1,810 | -6,984 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | -2,137 | 138 |
Net (Gain) Loss | 3,947 | -7,122 |
Prior Service Cost, Estimated | 25 | |
Net (Gain) Loss, Estimated | 0 | |
Mississippi Power [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 385,410 | 200,620 |
Other current liabilities | -44,701 | -21,413 |
Other regulatory liabilities, deferred | -63,681 | -144,992 |
Employee benefit obligations | -147,536 | -94,430 |
Accumulated OCI | -7,015 | -7,864 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Net Regulatory Assets | 171,764 | 66,604 |
Mississippi Power [Member] | Pension Plans [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Prepaid pension costs | 0 | 5,698 |
Other regulatory assets, deferred | 150,972 | 77,572 |
Other current liabilities | -2,337 | -2,134 |
Employee benefit obligations | -65,029 | -25,556 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | 3,030 | 4,118 |
Net (Gain) Loss | 147,942 | 73,454 |
Prior Service Cost, Estimated | 1,088 | |
Net (Gain) Loss, Estimated | 10,293 | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||
Amounts recognized in the consolidated balance sheets related to company's pension plans | ||
Other regulatory assets, deferred | 18,345 | 5,227 |
Other regulatory liabilities, deferred | -2,011 | -3,111 |
Employee benefit obligations | -71,532 | -57,663 |
Amounts related to defined benefit pension Plans that had not yet been recognized in net periodic pension cost along with estimated amortization | ||
Prior Service Cost | -2,123 | -2,311 |
Net (Gain) Loss | 18,457 | 4,427 |
Prior Service Cost, Estimated | -188 | |
Net (Gain) Loss, Estimated | 778 | |
Net Regulatory Assets | $16,334 | $2,116 |
Retirement_Benefits_Components
Retirement Benefits - Components of Accumulated OCI and Changes in Regulatory Assets (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | ($3,152,000,000) | ($1,634,000,000) | |
Reclassification adjustments | |||
Amortization of prior service costs | 26,000,000 | 27,000,000 | 30,000,000 |
Net periodic benefit cost | 139,000,000 | 245,000,000 | 135,000,000 |
Pension Plans, Defined Benefit [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -130,000,000 | -59,000,000 | |
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 64,000,000 | 125,000,000 | |
Net (gain) loss | 75,000,000 | -52,000,000 | |
Change in prior service costs | 0 | 0 | |
Reclassification adjustments | |||
Amortization of prior service costs | -1,000,000 | -1,000,000 | |
Amortization of net gain (loss) | -4,000,000 | -8,000,000 | |
Total reclassification adjustments | -5,000,000 | -9,000,000 | |
Net periodic benefit cost | 70,000,000 | -61,000,000 | |
Ending Balance | 134,000,000 | 64,000,000 | |
Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -3,022,000,000 | -1,575,000,000 | |
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 1,651,000,000 | 3,013,000,000 | |
Net (gain) loss | 1,552,000,000 | -1,145,000,000 | |
Change in prior service costs | -1,000,000 | -1,000,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | -25,000,000 | -26,000,000 | |
Amortization of net gain (loss) | -106,000,000 | -192,000,000 | |
Total reclassification adjustments | -131,000,000 | -218,000,000 | |
Net periodic benefit cost | 1,422,000,000 | -1,362,000,000 | |
Ending Balance | 3,073,000,000 | 1,651,000,000 | |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -372,000,000 | -65,000,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | 6,000,000 | 21,000,000 | 20,000,000 |
Net periodic benefit cost | 47,000,000 | 63,000,000 | 66,000,000 |
Other Postretirement Benefits [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -8,000,000 | -1,000,000 | |
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 1,000,000 | 7,000,000 | |
Net (gain) loss | 7,000,000 | -6,000,000 | |
Change in prior service costs | 0 | ||
Reclassification adjustments | |||
Amortization of transition obligation | 0 | ||
Amortization of prior service costs | 0 | 0 | |
Amortization of net gain (loss) | 0 | 0 | |
Total reclassification adjustments | 0 | 0 | |
Net periodic benefit cost | 7,000,000 | -6,000,000 | |
Ending Balance | 8,000,000 | 1,000,000 | |
Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -364,000,000 | -64,000,000 | |
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 73,000,000 | 360,000,000 | |
Net (gain) loss | 301,000,000 | -266,000,000 | |
Change in prior service costs | 2,000,000 | ||
Reclassification adjustments | |||
Amortization of transition obligation | -5,000,000 | ||
Amortization of prior service costs | -4,000,000 | -4,000,000 | |
Amortization of net gain (loss) | -2,000,000 | -12,000,000 | |
Total reclassification adjustments | -6,000,000 | -21,000,000 | |
Net periodic benefit cost | 293,000,000 | -287,000,000 | |
Ending Balance | 366,000,000 | 73,000,000 | |
Alabama Power [Member] | Pension Plans, Defined Benefit [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 7,000,000 | 7,000,000 | 7,000,000 |
Net periodic benefit cost | 21,000,000 | 47,000,000 | 6,000,000 |
Alabama Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -815,000,000 | -457,000,000 | |
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 476,000,000 | 822,000,000 | |
Net (gain) loss | 389,000,000 | -287,000,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | -7,000,000 | -7,000,000 | |
Amortization of net gain (loss) | -31,000,000 | -52,000,000 | |
Total reclassification adjustments | -38,000,000 | -59,000,000 | |
Net periodic benefit cost | 351,000,000 | -346,000,000 | |
Ending Balance | 827,000,000 | 476,000,000 | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 4,000,000 | 5,000,000 | 6,000,000 |
Net periodic benefit cost | 4,000,000 | 7,000,000 | 10,000,000 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -39,000,000 | 34,000,000 | |
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | -15,000,000 | 89,000,000 | |
Net (gain) loss | 73,000,000 | -99,000,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | -4,000,000 | -3,000,000 | |
Amortization of net gain (loss) | 0 | -2,000,000 | |
Total reclassification adjustments | -4,000,000 | -5,000,000 | |
Net periodic benefit cost | 69,000,000 | -104,000,000 | |
Ending Balance | 54,000,000 | -15,000,000 | |
Georgia Power [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -1,085,000,000 | -584,000,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | 10,000,000 | 10,000,000 | 12,000,000 |
Net periodic benefit cost | 38,000,000 | 79,000,000 | 25,000,000 |
Georgia Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 610,000,000 | 1,132,000,000 | |
Net (gain) loss | 543,000,000 | -438,000,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | -10,000,000 | -10,000,000 | |
Amortization of net gain (loss) | -41,000,000 | -74,000,000 | |
Total reclassification adjustments | -51,000,000 | -84,000,000 | |
Net periodic benefit cost | 492,000,000 | -522,000,000 | |
Ending Balance | 1,102,000,000 | 610,000,000 | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -218,000,000 | -73,000,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | 2,000,000 | 12,000,000 | 10,000,000 |
Net periodic benefit cost | 17,000,000 | 26,000,000 | 25,000,000 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 69,000,000 | 187,000,000 | |
Net (gain) loss | 146,000,000 | -106,000,000 | |
Reclassification adjustments | |||
Amortization of transition obligation | 0 | -4,000,000 | |
Amortization of net gain (loss) | -2,000,000 | -8,000,000 | |
Total reclassification adjustments | -2,000,000 | -12,000,000 | |
Net periodic benefit cost | 144,000,000 | -118,000,000 | |
Ending Balance | 213,000,000 | 69,000,000 | |
Gulf Power [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 1,115,000 | 1,164,000 | 1,262,000 |
Net periodic benefit cost | 6,820,000 | 11,563,000 | 5,543,000 |
Gulf Power [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -142,529,000 | -70,879,000 | |
Gulf Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 75,280,000 | 139,261,000 | |
Net (gain) loss | 76,209,000 | -54,432,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | -1,115,000 | -1,164,000 | |
Amortization of net gain (loss) | -4,559,000 | -8,385,000 | |
Total reclassification adjustments | -5,674,000 | -9,549,000 | |
Net periodic benefit cost | 70,535,000 | -63,981,000 | |
Ending Balance | 145,815,000 | 75,280,000 | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 162,000 | 186,000 | 379,000 |
Net periodic benefit cost | 3,254,000 | 3,285,000 | 3,602,000 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -3,947,000 | 7,122,000 | |
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | -6,984,000 | 2,169,000 | |
Net (gain) loss | 11,045,000 | -8,967,000 | |
Change in prior service costs | 2,089,000 | 0 | |
Reclassification adjustments | |||
Amortization of prior service costs | -186,000 | -186,000 | |
Amortization of net gain (loss) | 24,000 | 0 | |
Total reclassification adjustments | -162,000 | -186,000 | |
Net periodic benefit cost | 8,794,000 | -9,153,000 | |
Ending Balance | 1,810,000 | -6,984,000 | |
Mississippi Power [Member] | |||
Reclassification adjustments | |||
Amortization of prior service costs | 1,088,000 | 1,143,000 | 1,309,000 |
Net periodic benefit cost | 7,499,000 | 12,884,000 | 8,723,000 |
Mississippi Power [Member] | Pension Plans, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -147,942,000 | -73,454,000 | |
Mississippi Power [Member] | Pension Plans, Defined Benefit [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 77,572,000 | 146,838,000 | |
Net (gain) loss | 79,425,000 | -58,662,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | -1,088,000 | -1,143,000 | |
Amortization of net gain (loss) | -4,937,000 | -9,461,000 | |
Total reclassification adjustments | -6,025,000 | -10,604,000 | |
Net periodic benefit cost | 73,400,000 | -69,266,000 | |
Ending Balance | 150,972,000 | 77,572,000 | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax | -18,457,000 | -4,427,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | -188,000 | 471,000 | 470,000 |
Net periodic benefit cost | 3,064,000 | 3,769,000 | 4,111,000 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Net Regulatory Assets/Liabilities [Member] | |||
Changes in the Balance of AOCI and Regulatory Assets [Roll Forward] | |||
Beginning Balance | 2,116,000 | 15,454,000 | |
Net (gain) loss | 14,030,000 | -12,867,000 | |
Reclassification adjustments | |||
Amortization of prior service costs | 188,000 | 188,000 | |
Amortization of net gain (loss) | 0 | -659,000 | |
Total reclassification adjustments | 188,000 | -471,000 | |
Net periodic benefit cost | 14,218,000 | -13,338,000 | |
Ending Balance | $16,334,000 | $2,116,000 |
Retirement_Benefits_Components1
Retirement Benefits - Components of Net Periodic Benefit Cost and Estimated Future Benefit Payments (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | $21,000 | $24,000 | $21,000 |
Interest cost | 79,000 | 74,000 | 85,000 |
Expected return on plan assets | -59,000 | -56,000 | -60,000 |
Net amortization | 6,000 | 21,000 | 20,000 |
Net periodic benefit cost | 47,000 | 63,000 | 66,000 |
Benefit Payments | |||
Benefit Payments, 2015 | 118,000 | ||
Benefit Payments, 2016 | 124,000 | ||
Benefit Payments, 2017 | 129,000 | ||
Benefit Payments, 2018 | 132,000 | ||
Benefit Payments, 2019 | 134,000 | ||
Benefit Payments, 2020 to 2024 | 670,000 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2015 | -10,000 | ||
Subsidy Receipts, 2016 | -11,000 | ||
Subsidy Receipts, 2017 | -12,000 | ||
Subsidy Receipts, 2018 | -13,000 | ||
Subsidy Receipts, 2019 | -15,000 | ||
Subsidy Receipts, 2020 to 2024 | -79,000 | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2015 | 108,000 | ||
Benefit Payments and Subsidy Receipts, 2016 | 113,000 | ||
Benefit Payments and Subsidy Receipts, 2017 | 117,000 | ||
Benefit Payments and Subsidy Receipts, 2018 | 119,000 | ||
Benefit Payments and Subsidy Receipts, 2019 | 119,000 | ||
Benefit Payments and Subsidy Receipts, 2020 to 2024 | 591,000 | ||
Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 213,000 | 232,000 | 198,000 |
Interest cost | 435,000 | 389,000 | 393,000 |
Expected return on plan assets | -645,000 | -603,000 | -581,000 |
Recognized net (gain) loss | 110,000 | 200,000 | 95,000 |
Net amortization | 26,000 | 27,000 | 30,000 |
Net periodic benefit cost | 139,000 | 245,000 | 135,000 |
Benefit Payments | |||
Benefit Payments, 2015 | 522,000 | ||
Benefit Payments, 2016 | 450,000 | ||
Benefit Payments, 2017 | 478,000 | ||
Benefit Payments, 2018 | 499,000 | ||
Benefit Payments, 2019 | 524,000 | ||
Benefit Payments, 2020 to 2024 | 2,962,000 | ||
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 5,000 | 6,000 | 5,000 |
Interest cost | 20,000 | 19,000 | 22,000 |
Expected return on plan assets | -25,000 | -23,000 | -23,000 |
Net amortization | 4,000 | 5,000 | 6,000 |
Net periodic benefit cost | 4,000 | 7,000 | 10,000 |
Benefit Payments | |||
Benefit Payments, 2015 | 31,000 | ||
Benefit Payments, 2016 | 32,000 | ||
Benefit Payments, 2017 | 32,000 | ||
Benefit Payments, 2018 | 34,000 | ||
Benefit Payments, 2019 | 34,000 | ||
Benefit Payments, 2020 to 2024 | 172,000 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2015 | -3,000 | ||
Subsidy Receipts, 2016 | -3,000 | ||
Subsidy Receipts, 2017 | -4,000 | ||
Subsidy Receipts, 2018 | -4,000 | ||
Subsidy Receipts, 2019 | -4,000 | ||
Subsidy Receipts, 2020 to 2024 | -22,000 | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2015 | 28,000 | ||
Benefit Payments and Subsidy Receipts, 2016 | 29,000 | ||
Benefit Payments and Subsidy Receipts, 2017 | 28,000 | ||
Benefit Payments and Subsidy Receipts, 2018 | 30,000 | ||
Benefit Payments and Subsidy Receipts, 2019 | 30,000 | ||
Benefit Payments and Subsidy Receipts, 2020 to 2024 | 150,000 | ||
Alabama Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 48,000 | 52,000 | 44,000 |
Interest cost | 103,000 | 93,000 | 94,000 |
Expected return on plan assets | -168,000 | -157,000 | -162,000 |
Recognized net (gain) loss | 31,000 | 52,000 | 23,000 |
Net amortization | 7,000 | 7,000 | 7,000 |
Net periodic benefit cost | 21,000 | 47,000 | 6,000 |
Benefit Payments | |||
Benefit Payments, 2015 | 127,000 | ||
Benefit Payments, 2016 | 114,000 | ||
Benefit Payments, 2017 | 120,000 | ||
Benefit Payments, 2018 | 125,000 | ||
Benefit Payments, 2019 | 129,000 | ||
Benefit Payments, 2020 to 2024 | 708,000 | ||
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 6,000 | 7,000 | 7,000 |
Interest cost | 34,000 | 31,000 | 37,000 |
Expected return on plan assets | -25,000 | -24,000 | -29,000 |
Net amortization | 2,000 | 12,000 | 10,000 |
Net periodic benefit cost | 17,000 | 26,000 | 25,000 |
Benefit Payments | |||
Benefit Payments, 2015 | 53,000 | ||
Benefit Payments, 2016 | 56,000 | ||
Benefit Payments, 2017 | 57,000 | ||
Benefit Payments, 2018 | 59,000 | ||
Benefit Payments, 2019 | 59,000 | ||
Benefit Payments, 2020 to 2024 | 289,000 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2015 | -4,000 | ||
Subsidy Receipts, 2016 | -5,000 | ||
Subsidy Receipts, 2017 | -5,000 | ||
Subsidy Receipts, 2018 | -6,000 | ||
Subsidy Receipts, 2019 | -6,000 | ||
Subsidy Receipts, 2020 to 2024 | -32,000 | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2015 | 49,000 | ||
Benefit Payments and Subsidy Receipts, 2016 | 51,000 | ||
Benefit Payments and Subsidy Receipts, 2017 | 52,000 | ||
Benefit Payments and Subsidy Receipts, 2018 | 53,000 | ||
Benefit Payments and Subsidy Receipts, 2019 | 53,000 | ||
Benefit Payments and Subsidy Receipts, 2020 to 2024 | 257,000 | ||
Georgia Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 62,000 | 69,000 | 60,000 |
Interest cost | 153,000 | 138,000 | 141,000 |
Expected return on plan assets | -228,000 | -212,000 | -221,000 |
Recognized net (gain) loss | 41,000 | 74,000 | 33,000 |
Net amortization | 10,000 | 10,000 | 12,000 |
Net periodic benefit cost | 38,000 | 79,000 | 25,000 |
Benefit Payments | |||
Benefit Payments, 2015 | 199,000 | ||
Benefit Payments, 2016 | 169,000 | ||
Benefit Payments, 2017 | 177,000 | ||
Benefit Payments, 2018 | 183,000 | ||
Benefit Payments, 2019 | 190,000 | ||
Benefit Payments, 2020 to 2024 | 1,042,000 | ||
Gulf Power [Member] | |||
Components of net periodic | |||
Service cost | 10,181 | 11,128 | 9,101 |
Interest cost | 19,433 | 17,321 | 17,199 |
Expected return on plan assets | -28,468 | -26,435 | -25,932 |
Recognized net (gain) loss | 4,559 | 8,385 | 3,913 |
Net amortization | 1,115 | 1,164 | 1,262 |
Net periodic benefit cost | 6,820 | 11,563 | 5,543 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 1,163 | 1,355 | 1,167 |
Interest cost | 3,235 | 2,982 | 3,367 |
Expected return on plan assets | -1,306 | -1,238 | -1,311 |
Net amortization | 162 | 186 | 379 |
Net periodic benefit cost | 3,254 | 3,285 | 3,602 |
Benefit Payments | |||
Benefit Payments, 2015 | 4,694 | ||
Benefit Payments, 2016 | 4,982 | ||
Benefit Payments, 2017 | 5,136 | ||
Benefit Payments, 2018 | 5,300 | ||
Benefit Payments, 2019 | 5,326 | ||
Benefit Payments, 2020 to 2024 | 27,399 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2015 | -431 | ||
Subsidy Receipts, 2016 | -480 | ||
Subsidy Receipts, 2017 | -535 | ||
Subsidy Receipts, 2018 | -594 | ||
Subsidy Receipts, 2019 | -660 | ||
Subsidy Receipts, 2020 to 2024 | -3,430 | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2015 | 4,263 | ||
Benefit Payments and Subsidy Receipts, 2016 | 4,502 | ||
Benefit Payments and Subsidy Receipts, 2017 | 4,601 | ||
Benefit Payments and Subsidy Receipts, 2018 | 4,706 | ||
Benefit Payments and Subsidy Receipts, 2019 | 4,666 | ||
Benefit Payments and Subsidy Receipts, 2020 to 2024 | 23,969 | ||
Gulf Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 10,181 | 11,128 | |
Interest cost | 19,433 | 17,321 | |
Benefit Payments | |||
Benefit Payments, 2015 | 22,002 | ||
Benefit Payments, 2016 | 18,683 | ||
Benefit Payments, 2017 | 19,950 | ||
Benefit Payments, 2018 | 21,019 | ||
Benefit Payments, 2019 | 22,229 | ||
Benefit Payments, 2020 to 2024 | 129,877 | ||
Mississippi Power [Member] | |||
Components of net periodic | |||
Service cost | 10,123 | 11,067 | 9,416 |
Interest cost | 20,093 | 18,062 | 18,019 |
Expected return on plan assets | -28,742 | -26,849 | -24,121 |
Recognized net (gain) loss | 4,937 | 9,461 | 4,100 |
Net amortization | 1,088 | 1,143 | 1,309 |
Net periodic benefit cost | 7,499 | 12,884 | 8,723 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||
Components of net periodic | |||
Service cost | 1,025 | 1,151 | 1,038 |
Interest cost | 3,812 | 3,619 | 4,155 |
Expected return on plan assets | -1,585 | -1,472 | -1,552 |
Net amortization | -188 | 471 | 470 |
Net periodic benefit cost | 3,064 | 3,769 | 4,111 |
Benefit Payments | |||
Benefit Payments, 2015 | 5,387 | ||
Benefit Payments, 2016 | 5,632 | ||
Benefit Payments, 2017 | 5,911 | ||
Benefit Payments, 2018 | 6,185 | ||
Benefit Payments, 2019 | 6,475 | ||
Benefit Payments, 2020 to 2024 | 34,139 | ||
Subsidy Receipts | |||
Subsidy Receipts, 2015 | -512 | ||
Subsidy Receipts, 2016 | -566 | ||
Subsidy Receipts, 2017 | -622 | ||
Subsidy Receipts, 2018 | -680 | ||
Subsidy Receipts, 2019 | -735 | ||
Subsidy Receipts, 2020 to 2024 | -3,744 | ||
Benefit Payments and Subsidy Receipts, Total | |||
Benefit Payments and Subsidy Receipts, 2015 | 4,875 | ||
Benefit Payments and Subsidy Receipts, 2016 | 5,066 | ||
Benefit Payments and Subsidy Receipts, 2017 | 5,289 | ||
Benefit Payments and Subsidy Receipts, 2018 | 5,505 | ||
Benefit Payments and Subsidy Receipts, 2019 | 5,740 | ||
Benefit Payments and Subsidy Receipts, 2020 to 2024 | 30,395 | ||
Mississippi Power [Member] | Pension Plans [Member] | |||
Components of net periodic | |||
Service cost | 10,123 | 11,067 | |
Interest cost | 20,093 | 18,062 | |
Benefit Payments | |||
Benefit Payments, 2015 | 23,304 | ||
Benefit Payments, 2016 | 19,551 | ||
Benefit Payments, 2017 | 20,816 | ||
Benefit Payments, 2018 | 21,905 | ||
Benefit Payments, 2019 | 23,337 | ||
Benefit Payments, 2020 to 2024 | $135,320 |
Retirement_Benefits_Pension_Pl
Retirement Benefits - Pension Plan and Other Postretirement Benefit Plan Assets (Details) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 31.00% |
Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 25.00% |
Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 27.00% | 23.00% |
Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 1.00% | 1.00% |
Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 14.00% | 14.00% |
Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 5.00% | 6.00% |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 42.00% | |
Defined Benefit Plan Assets | 41.00% | 40.00% |
Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 21.00% | |
Defined Benefit Plan Assets | 23.00% | 25.00% |
Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 24.00% | |
Defined Benefit Plan Assets | 26.00% | 24.00% |
Other Postretirement Benefits [Member] | Global fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 4.00% | |
Defined Benefit Plan Assets | 3.00% | 4.00% |
Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 1.00% | |
Defined Benefit Plan Assets | 0.00% | 0.00% |
Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 5.00% | |
Defined Benefit Plan Assets | 5.00% | 5.00% |
Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 2.00% |
Alabama Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Alabama Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 31.00% |
Alabama Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 25.00% |
Alabama Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 27.00% | 23.00% |
Alabama Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 1.00% | 1.00% |
Alabama Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 14.00% | 14.00% |
Alabama Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 5.00% | 6.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 48.00% | |
Defined Benefit Plan Assets | 48.00% | 47.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 20.00% | |
Defined Benefit Plan Assets | 20.00% | 20.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 24.00% | |
Defined Benefit Plan Assets | 26.00% | 27.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 1.00% | |
Defined Benefit Plan Assets | 0.00% | 0.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 4.00% | |
Defined Benefit Plan Assets | 4.00% | 4.00% |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 2.00% | 2.00% |
Georgia Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Georgia Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 31.00% |
Georgia Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 25.00% |
Georgia Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 27.00% | 23.00% |
Georgia Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 1.00% | 1.00% |
Georgia Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 14.00% | 14.00% |
Georgia Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 5.00% | 6.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 40.00% | |
Defined Benefit Plan Assets | 38.00% | 36.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 21.00% | |
Defined Benefit Plan Assets | 26.00% | 30.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 24.00% | |
Defined Benefit Plan Assets | 24.00% | 21.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Global fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 8.00% | |
Defined Benefit Plan Assets | 7.00% | 8.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 1.00% | |
Defined Benefit Plan Assets | 0.00% | 0.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 4.00% | |
Defined Benefit Plan Assets | 4.00% | 3.00% |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 2.00% | |
Defined Benefit Plan Assets | 1.00% | 2.00% |
Gulf Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Gulf Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 31.00% |
Gulf Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 25.00% |
Gulf Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 27.00% | 23.00% |
Gulf Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 1.00% | 1.00% |
Gulf Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 14.00% | 14.00% |
Gulf Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 5.00% | 6.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 29.00% | 30.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 24.00% | |
Defined Benefit Plan Assets | 22.00% | 24.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 29.00% | 25.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 1.00% | 1.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 14.00% | 14.00% |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 5.00% | 6.00% |
Mississippi Power [Member] | Pension Plans [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Mississippi Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 26.00% | |
Defined Benefit Plan Assets | 30.00% | 31.00% |
Mississippi Power [Member] | Pension Plans [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 25.00% | |
Defined Benefit Plan Assets | 23.00% | 25.00% |
Mississippi Power [Member] | Pension Plans [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 23.00% | |
Defined Benefit Plan Assets | 27.00% | 23.00% |
Mississippi Power [Member] | Pension Plans [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 1.00% | 1.00% |
Mississippi Power [Member] | Pension Plans [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 14.00% | |
Defined Benefit Plan Assets | 14.00% | 14.00% |
Mississippi Power [Member] | Pension Plans [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 9.00% | |
Defined Benefit Plan Assets | 5.00% | 6.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 100.00% | |
Defined Benefit Plan Assets | 100.00% | 100.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 21.00% | |
Defined Benefit Plan Assets | 24.00% | 25.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 21.00% | |
Defined Benefit Plan Assets | 19.00% | 20.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Fixed income [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 37.00% | |
Defined Benefit Plan Assets | 41.00% | 38.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Special situations [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 3.00% | |
Defined Benefit Plan Assets | 1.00% | 1.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 11.00% | |
Defined Benefit Plan Assets | 11.00% | 11.00% |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | ||
Defined Benefit Plan, Assets, Target Allocations [Abstract] | ||
Defined Benefit Plan Assets, Target | 7.00% | |
Defined Benefit Plan Assets | 4.00% | 5.00% |
Retirement_Benefits_Fair_Value
Retirement Benefits - Fair Values of Pension Plan and Other Postretirement Benefit Plan Assets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Thousands, unless otherwise specified | |||||
Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | $9,647,000 | $8,650,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -2,000 | -3,000 | |||
Fair Value, Plan Assets and Liabilities | 9,645,000 | 8,647,000 | |||
Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,408,000 | [1] | 2,272,000 | [2] | |
Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,056,000 | [1] | 2,119,000 | [2] | |
Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 699,000 | 599,000 | |||
Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 188,000 | 156,000 | |||
Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,135,000 | 978,000 | |||
Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 514,000 | 471,000 | |||
Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 663,000 | 224,000 | |||
Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,414,000 | 1,260,000 | |||
Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 570,000 | 571,000 | |||
Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 905,000 | 898,000 | |||
Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 203,000 | [3] | 202,000 | [2] | |
Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 103,000 | [3] | 121,000 | [2] | |
Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 29,000 | 34,000 | |||
Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,000 | 6,000 | |||
Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 39,000 | 35,000 | |||
Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 41,000 | 46,000 | |||
Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 36,000 | 19,000 | |||
Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 381,000 | 369,000 | |||
Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 48,000 | 46,000 | |||
Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 19,000 | 20,000 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,070,000 | 2,795,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -2,000 | 0 | |||
Fair Value, Plan Assets and Liabilities | 3,068,000 | 2,795,000 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,704,000 | [1] | 1,433,000 | [2] | |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,070,000 | [1] | 1,101,000 | [2] | |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,000 | 1,000 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 293,000 | 260,000 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 203,000 | 206,000 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 147,000 | [3] | 157,000 | [2] | |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 36,000 | [3] | 39,000 | [2] | |
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 9,000 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 11,000 | 10,000 | |||
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 4,886,000 | 4,284,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | -3,000 | |||
Fair Value, Plan Assets and Liabilities | 4,886,000 | 4,281,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 704,000 | [1] | 839,000 | [2] | |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 986,000 | [1] | 1,018,000 | [2] | |
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 699,000 | 599,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 188,000 | 156,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,135,000 | 978,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 514,000 | 471,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 660,000 | 223,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 646,000 | 636,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 56,000 | [3] | 45,000 | [2] | |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 67,000 | [3] | 82,000 | [2] | |
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 29,000 | 34,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,000 | 6,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 39,000 | 35,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 41,000 | 46,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 27,000 | 19,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 381,000 | 369,000 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,691,000 | 1,571,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | 0 | |||
Fair Value, Plan Assets and Liabilities | 1,691,000 | 1,571,000 | |||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [1] | 0 | [2] | |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [1] | 0 | [2] | |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,121,000 | 1,000,000 | 841,000 | ||
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 570,000 | 571,000 | 593,000 | ||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 56,000 | 56,000 | |||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [3] | 0 | [2] | |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [3] | 0 | [2] | |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 37,000 | 36,000 | 30,000 | ||
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 19,000 | 20,000 | 21,000 | ||
Alabama Power [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,385,000 | 2,256,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -1,000 | ||||
Fair Value, Plan Assets and Liabilities | 2,255,000 | ||||
Alabama Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 595,000 | [2] | 593,000 | [2] | |
Alabama Power [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 508,000 | [2] | 552,000 | [2] | |
Alabama Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 173,000 | 156,000 | |||
Alabama Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 47,000 | 41,000 | |||
Alabama Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 280,000 | 255,000 | |||
Alabama Power [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 127,000 | 123,000 | |||
Alabama Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 164,000 | 58,000 | |||
Alabama Power [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 350,000 | 329,000 | |||
Alabama Power [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 141,000 | 149,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 391,000 | 387,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 84,000 | [2] | 78,000 | [2] | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 25,000 | [2] | 27,000 | [2] | |
Alabama Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 10,000 | 17,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,000 | 2,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 14,000 | 12,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,000 | 6,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,000 | 10,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 217,000 | 211,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 18,000 | 17,000 | |||
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 7,000 | 7,000 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 759,000 | 729,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | ||||
Fair Value, Plan Assets and Liabilities | 729,000 | ||||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 421,000 | [2] | 374,000 | [2] | |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 264,000 | [2] | 287,000 | [2] | |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,000 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 73,000 | 68,000 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 94,000 | 85,000 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 76,000 | [2] | 67,000 | [2] | |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 13,000 | [2] | 14,000 | [2] | |
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 5,000 | 4,000 | |||
Alabama Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,208,000 | 1,117,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -1,000 | ||||
Fair Value, Plan Assets and Liabilities | 1,116,000 | ||||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 174,000 | [2] | 219,000 | [2] | |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 244,000 | [2] | 265,000 | [2] | |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 173,000 | 156,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 47,000 | 41,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 280,000 | 255,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 127,000 | 123,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 163,000 | 58,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 277,000 | 282,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,000 | [2] | 11,000 | [2] | |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 12,000 | [2] | 13,000 | [2] | |
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 10,000 | 17,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,000 | 2,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 14,000 | 12,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,000 | 6,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,000 | 10,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 217,000 | 211,000 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 418,000 | 410,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | ||||
Fair Value, Plan Assets and Liabilities | 410,000 | ||||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 277,000 | 261,000 | 220,000 | ||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 141,000 | 149,000 | 155,000 | ||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 20,000 | 20,000 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 13,000 | 13,000 | 11,000 | ||
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 7,000 | 7,000 | 8,000 | ||
Georgia Power [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,368,000 | 3,055,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -1,000 | -1,000 | |||
Fair Value, Plan Assets and Liabilities | 3,367,000 | 3,054,000 | |||
Georgia Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 841,000 | [2] | 802,000 | [2] | |
Georgia Power [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 717,000 | [2] | 748,000 | [2] | |
Georgia Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 244,000 | 212,000 | |||
Georgia Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 66,000 | 55,000 | |||
Georgia Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 398,000 | 346,000 | |||
Georgia Power [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 179,000 | 166,000 | |||
Georgia Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 231,000 | 79,000 | |||
Georgia Power [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 493,000 | 445,000 | |||
Georgia Power [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 199,000 | 202,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 401,000 | 406,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 93,000 | [2] | 99,000 | [2] | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 56,000 | [2] | 69,000 | [2] | |
Georgia Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 7,000 | 7,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,000 | 2,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 12,000 | 11,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 29,000 | 34,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 19,000 | 6,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 162,000 | 158,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 15,000 | 14,000 | |||
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,000 | 6,000 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,071,000 | 987,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -1,000 | 0 | |||
Fair Value, Plan Assets and Liabilities | 1,070,000 | 987,000 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 595,000 | [2] | 506,000 | [2] | |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 373,000 | [2] | 389,000 | [2] | |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,000 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 102,000 | 92,000 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 75,000 | 89,000 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 53,000 | [2] | 74,000 | [2] | |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 11,000 | [2] | 12,000 | [2] | |
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,000 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,000 | 3,000 | |||
Georgia Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,707,000 | 1,513,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | -1,000 | |||
Fair Value, Plan Assets and Liabilities | 1,707,000 | 1,512,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 246,000 | [2] | 296,000 | [2] | |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 344,000 | [2] | 359,000 | [2] | |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 244,000 | 212,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 66,000 | 55,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 398,000 | 346,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 179,000 | 166,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 230,000 | 79,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 308,000 | 300,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 40,000 | [2] | 25,000 | [2] | |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 45,000 | [2] | 57,000 | [2] | |
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 7,000 | 7,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,000 | 2,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 12,000 | 11,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 29,000 | 34,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 11,000 | 6,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 162,000 | 158,000 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 590,000 | 555,000 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | 0 | |||
Fair Value, Plan Assets and Liabilities | 590,000 | 555,000 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 391,000 | 353,000 | 299,000 | ||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 199,000 | 202,000 | 211,000 | ||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 18,000 | 17,000 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Trust-owned life insurance [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 12,000 | 11,000 | 10,000 | ||
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,000 | 6,000 | 7,000 | ||
Gulf Power [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 432,798 | 381,941 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -87 | -115 | |||
Fair Value, Plan Assets and Liabilities | 432,711 | 381,826 | |||
Gulf Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 108,048 | [2] | 100,306 | [2] | |
Gulf Power [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 92,211 | [2] | 93,547 | [2] | |
Gulf Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 31,372 | 26,461 | |||
Gulf Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,438 | 6,873 | |||
Gulf Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 50,931 | 43,222 | |||
Gulf Power [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 23,063 | 20,810 | |||
Gulf Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 29,727 | 9,889 | |||
Gulf Power [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 63,435 | 55,632 | |||
Gulf Power [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 25,573 | 25,201 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 18,087 | 17,278 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -4 | -5 | |||
Fair Value, Plan Assets and Liabilities | 18,083 | 17,273 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 4,388 | [2] | 4,406 | [2] | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,747 | [2] | 4,109 | [2] | |
Gulf Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,274 | 1,161 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 342 | 303 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,071 | 1,897 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 937 | 1,417 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,713 | 434 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,576 | 2,443 | |||
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,039 | 1,108 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 137,732 | 123,406 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -87 | 0 | |||
Fair Value, Plan Assets and Liabilities | 137,645 | 123,406 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 76,460 | [2] | 63,269 | [2] | |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 47,988 | [2] | 48,606 | [2] | |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 130 | 38 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 13,154 | 11,493 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,098 | 5,419 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -4 | 0 | |||
Fair Value, Plan Assets and Liabilities | 6,094 | 5,419 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,105 | [2] | 2,778 | [2] | |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,949 | [2] | 2,136 | [2] | |
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 510 | 1 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 534 | 504 | |||
Gulf Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 219,212 | 189,195 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | -115 | |||
Fair Value, Plan Assets and Liabilities | 219,212 | 189,080 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 31,588 | [2] | 37,037 | [2] | |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 44,223 | [2] | 44,941 | [2] | |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 31,372 | 26,461 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,438 | 6,873 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 50,931 | 43,222 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 23,063 | 20,810 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 29,597 | 9,851 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,908 | 8,812 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | -5 | |||
Fair Value, Plan Assets and Liabilities | 8,908 | 8,807 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,283 | [2] | 1,628 | [2] | |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,798 | [2] | 1,973 | [2] | |
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,274 | 1,161 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 342 | 303 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,071 | 1,897 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 937 | 1,417 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,203 | 433 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 75,854 | 69,340 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | 0 | |||
Fair Value, Plan Assets and Liabilities | 75,854 | 69,340 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 50,281 | 44,139 | 37,039 | ||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 25,573 | 25,201 | 26,129 | ||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,081 | 3,047 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | 0 | |||
Fair Value, Plan Assets and Liabilities | 3,081 | 3,047 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,042 | 1,939 | 1,667 | ||
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,039 | 1,108 | 1,155 | ||
Mississippi Power [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 443,463 | 383,687 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -89 | -115 | |||
Fair Value, Plan Assets and Liabilities | 443,374 | 383,572 | |||
Mississippi Power [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 110,710 | [2] | 100,764 | [2] | |
Mississippi Power [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 94,483 | [2] | 93,975 | [2] | |
Mississippi Power [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 32,145 | 26,582 | |||
Mississippi Power [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,646 | 6,904 | |||
Mississippi Power [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 52,185 | 43,420 | |||
Mississippi Power [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 23,632 | 20,905 | |||
Mississippi Power [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 30,460 | 9,934 | |||
Mississippi Power [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 64,999 | 55,887 | |||
Mississippi Power [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 26,203 | 25,316 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 23,980 | 23,057 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -5 | -5 | |||
Fair Value, Plan Assets and Liabilities | 23,975 | 23,052 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 4,875 | [2] | 4,898 | [2] | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 4,162 | [2] | 4,568 | [2] | |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 5,279 | 5,213 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 380 | 337 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,301 | 2,109 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,041 | 1,016 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,926 | 969 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,862 | 2,716 | |||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,154 | 1,231 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 141,126 | 123,971 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -89 | 0 | |||
Fair Value, Plan Assets and Liabilities | 141,037 | 123,971 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 78,344 | [2] | 63,558 | [2] | |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 49,170 | [2] | 48,829 | [2] | |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 133 | 38 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 13,479 | 11,546 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 6,797 | 6,025 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | -5 | 0 | |||
Fair Value, Plan Assets and Liabilities | 6,792 | 6,025 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,450 | [2] | 3,089 | [2] | |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,165 | [2] | 2,375 | [2] | |
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 589 | 1 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 593 | 560 | |||
Mississippi Power [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 224,614 | 190,059 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | -115 | |||
Fair Value, Plan Assets and Liabilities | 224,614 | 189,944 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 32,366 | [2] | 37,206 | [2] | |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 45,313 | [2] | 45,146 | [2] | |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 32,145 | 26,582 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 8,646 | 6,904 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 52,185 | 43,420 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 23,632 | 20,905 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 30,327 | 9,896 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 13,760 | 13,645 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | -5 | |||
Fair Value, Plan Assets and Liabilities | 13,760 | 13,640 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,425 | [2] | 1,809 | [2] | |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,997 | [2] | 2,193 | [2] | |
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 5,279 | 5,213 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 380 | 337 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,301 | 2,109 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,041 | 1,016 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 1,337 | 968 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 77,723 | 69,657 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | 0 | |||
Fair Value, Plan Assets and Liabilities | 77,723 | 69,657 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 51,520 | 44,341 | 37,196 | ||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 26,203 | 25,316 | 26,240 | ||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 3,423 | 3,387 | |||
Liabilities Fair Value | |||||
Fair Value, Plan Liabilities | 0 | 0 | |||
Fair Value, Plan Assets and Liabilities | 3,423 | 3,387 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Domestic Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | International Equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | [2] | 0 | [2] | |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | U.S. Treasury, government, and agency bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Mortgage and asset backed securities [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Corporate bonds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Pooled funds [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Cash equivalents and other [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 0 | 0 | |||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real estate investments [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | 2,269 | 2,156 | 1,865 | ||
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private equity [Member] | |||||
Assets Fair Value | |||||
Fair Value, Plan Assets | $1,154 | $1,231 | $1,293 | ||
[1] | *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.B Fair Value Measurements Using Quoted Prices in Active Markets for Identical AssetsB SignificantOtherObservableInputsB SignificantUnobservableInputs As of December 31, 2013:(Level 1)B (Level 2)B (Level 3)B TotalB (in millions)Assets: Domestic equity*$1,433B $839B $bB $2,272International equity*1,101B 1,018B bB 2,119Fixed income: U.S. Treasury, government, and agency bondsbB 599B bB 599Mortgage- and asset-backed securitiesbB 156B bB 156Corporate bondsbB 978B bB 978Pooled fundsbB 471B bB 471Cash equivalents and other1B 223B bB 224Real estate investments260B bB 1,000B 1,260Private equitybB bB 571B 571Total$2,795B $4,284B $1,571B $8,650Liabilities: Derivatives$bB $(3)B $bB $(3)Total$2,795B $4,281B $1,571B $8,647 | ||||
[2] | *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk. | ||||
[3] | *Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.B Fair Value Measurements Using QuotedB Prices in Active Markets for Identical AssetsB SignificantOtherObservableInputsB SignificantUnobservableInputs As of December 31, 2013:(Level 1)B (Level 2)B (Level 3)B TotalB (in millions)Assets: Domestic equity*$157B $45B $bB $202International equity*39B 82B bB 121Fixed income: U.S. Treasury, government, and agency bondsbB 34B bB 34Mortgage- and asset-backed securitiesbB 6B bB 6Corporate bondsbB 35B bB 35Pooled fundsbB 46B bB 46Cash equivalents and otherbB 19B bB 19Trust-owned life insurancebB 369B bB 369Real estate investments10B bB 36B 46Private equitybB bB 20B 20Total$206B $636B $56B $898 |
Retirement_Benefits_Changes_in1
Retirement Benefits - Changes in Fair Value Measurement of Level 3 Pension Plan Assets (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Plans [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | $8,650,000 | |
Actual return on investments: | ||
Total return on investments | 797,000 | 1,098,000 |
Fair value of plan assets end of year | 9,647,000 | 8,650,000 |
Pension Plans [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 1,414,000 | 1,260,000 |
Pension Plans [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 570,000 | 571,000 |
Other Postretirement Benefits [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 898,000 | |
Actual return on investments: | ||
Total return on investments | 54,000 | 129,000 |
Fair value of plan assets end of year | 905,000 | 898,000 |
Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 48,000 | 46,000 |
Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 19,000 | 20,000 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 1,691,000 | 1,571,000 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 1,000,000 | 841,000 |
Actual return on investments: | ||
Related to investments held at year end | 79,000 | 74,000 |
Related to investments sold during the year | 33,000 | 30,000 |
Total return on investments | 112,000 | 104,000 |
Purchases, sales, and settlements | 9,000 | 55,000 |
Fair value of plan assets end of year | 1,121,000 | 1,000,000 |
Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 571,000 | 593,000 |
Actual return on investments: | ||
Related to investments held at year end | 51,000 | 8,000 |
Related to investments sold during the year | -16,000 | 51,000 |
Total return on investments | 35,000 | 59,000 |
Purchases, sales, and settlements | -36,000 | -81,000 |
Fair value of plan assets end of year | 570,000 | 571,000 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 56,000 | 56,000 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 36,000 | 30,000 |
Actual return on investments: | ||
Related to investments held at year end | 1,000 | 3,000 |
Related to investments sold during the year | 0 | 1,000 |
Total return on investments | 1,000 | 4,000 |
Purchases, sales, and settlements | 0 | 2,000 |
Fair value of plan assets end of year | 37,000 | 36,000 |
Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 20,000 | 21,000 |
Actual return on investments: | ||
Related to investments held at year end | 1,000 | 0 |
Related to investments sold during the year | -1,000 | 2,000 |
Total return on investments | 0 | 2,000 |
Purchases, sales, and settlements | -1,000 | -3,000 |
Fair value of plan assets end of year | 19,000 | 20,000 |
Alabama Power [Member] | Pension Plans [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 2,256,000 | |
Actual return on investments: | ||
Total return on investments | 207,000 | 285,000 |
Fair value of plan assets end of year | 2,385,000 | 2,256,000 |
Alabama Power [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 350,000 | 329,000 |
Alabama Power [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 141,000 | 149,000 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 387,000 | |
Actual return on investments: | ||
Total return on investments | 23,000 | 61,000 |
Fair value of plan assets end of year | 391,000 | 387,000 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 18,000 | 17,000 |
Alabama Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 7,000 | 7,000 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 418,000 | 410,000 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 261,000 | 220,000 |
Actual return on investments: | ||
Related to investments held at year end | 6,000 | 19,000 |
Related to investments sold during the year | 8,000 | 8,000 |
Total return on investments | 14,000 | 27,000 |
Purchases, sales, and settlements | 2,000 | 14,000 |
Fair value of plan assets end of year | 277,000 | 261,000 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 149,000 | 155,000 |
Actual return on investments: | ||
Related to investments held at year end | 5,000 | 2,000 |
Related to investments sold during the year | -4,000 | 13,000 |
Total return on investments | 1,000 | 15,000 |
Purchases, sales, and settlements | -9,000 | -21,000 |
Fair value of plan assets end of year | 141,000 | 149,000 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 20,000 | 20,000 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 13,000 | 11,000 |
Actual return on investments: | ||
Related to investments held at year end | 0 | 1,000 |
Related to investments sold during the year | 0 | 0 |
Total return on investments | 0 | 1,000 |
Purchases, sales, and settlements | 0 | 1,000 |
Fair value of plan assets end of year | 13,000 | 13,000 |
Alabama Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 7,000 | 8,000 |
Actual return on investments: | ||
Related to investments held at year end | 0 | 0 |
Related to investments sold during the year | 0 | 0 |
Total return on investments | 0 | 0 |
Purchases, sales, and settlements | 0 | -1,000 |
Fair value of plan assets end of year | 7,000 | 7,000 |
Georgia Power [Member] | Pension Plans [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 3,055,000 | |
Actual return on investments: | ||
Total return on investments | 285,000 | 387,000 |
Fair value of plan assets end of year | 3,368,000 | 3,055,000 |
Georgia Power [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 493,000 | 445,000 |
Georgia Power [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 199,000 | 202,000 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 406,000 | |
Actual return on investments: | ||
Total return on investments | 21,000 | 56,000 |
Fair value of plan assets end of year | 401,000 | 406,000 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 15,000 | 14,000 |
Georgia Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 6,000 | 6,000 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 590,000 | 555,000 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 353,000 | 299,000 |
Actual return on investments: | ||
Related to investments held at year end | 23,000 | 25,000 |
Related to investments sold during the year | 12,000 | 10,000 |
Total return on investments | 35,000 | 35,000 |
Purchases, sales, and settlements | 3,000 | 19,000 |
Fair value of plan assets end of year | 391,000 | 353,000 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 202,000 | 211,000 |
Actual return on investments: | ||
Related to investments held at year end | 15,000 | 3,000 |
Related to investments sold during the year | -6,000 | 17,000 |
Total return on investments | 9,000 | 20,000 |
Purchases, sales, and settlements | -12,000 | -29,000 |
Fair value of plan assets end of year | 199,000 | 202,000 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 18,000 | 17,000 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 11,000 | 10,000 |
Actual return on investments: | ||
Related to investments held at year end | 1,000 | 1,000 |
Related to investments sold during the year | 0 | 0 |
Total return on investments | 1,000 | 1,000 |
Purchases, sales, and settlements | 0 | 0 |
Fair value of plan assets end of year | 12,000 | 11,000 |
Georgia Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 6,000 | 7,000 |
Actual return on investments: | ||
Related to investments held at year end | 0 | 0 |
Related to investments sold during the year | 0 | 0 |
Total return on investments | 0 | 0 |
Purchases, sales, and settlements | 0 | -1,000 |
Fair value of plan assets end of year | 6,000 | 6,000 |
Gulf Power [Member] | Pension Plans [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 381,941 | |
Actual return on investments: | ||
Total return on investments | 33,512 | 49,076 |
Fair value of plan assets end of year | 432,798 | 381,941 |
Gulf Power [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 63,435 | 55,632 |
Gulf Power [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 25,573 | 25,201 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 17,278 | |
Actual return on investments: | ||
Total return on investments | 1,578 | 2,119 |
Fair value of plan assets end of year | 18,087 | 17,278 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 2,576 | 2,443 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 1,039 | 1,108 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 75,854 | 69,340 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 44,139 | 37,039 |
Actual return on investments: | ||
Related to investments held at year end | 4,263 | 3,357 |
Related to investments sold during the year | 1,488 | 1,310 |
Total return on investments | 5,751 | 4,667 |
Purchases, sales, and settlements | 391 | 2,433 |
Fair value of plan assets end of year | 50,281 | 44,139 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 25,201 | 26,129 |
Actual return on investments: | ||
Related to investments held at year end | 2,697 | 376 |
Related to investments sold during the year | -727 | 2,282 |
Total return on investments | 1,970 | 2,658 |
Purchases, sales, and settlements | -1,598 | -3,586 |
Fair value of plan assets end of year | 25,573 | 25,201 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 3,081 | 3,047 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 1,939 | 1,667 |
Actual return on investments: | ||
Related to investments held at year end | 27 | 108 |
Related to investments sold during the year | 60 | 57 |
Total return on investments | 87 | 165 |
Purchases, sales, and settlements | 16 | 107 |
Fair value of plan assets end of year | 2,042 | 1,939 |
Gulf Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 1,108 | 1,155 |
Actual return on investments: | ||
Related to investments held at year end | 26 | 16 |
Related to investments sold during the year | -30 | 104 |
Total return on investments | -4 | 120 |
Purchases, sales, and settlements | -65 | -167 |
Fair value of plan assets end of year | 1,039 | 1,108 |
Mississippi Power [Member] | Pension Plans [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 383,687 | |
Actual return on investments: | ||
Total return on investments | 40,051 | 49,431 |
Fair value of plan assets end of year | 443,463 | 383,687 |
Mississippi Power [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 64,999 | 55,887 |
Mississippi Power [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 26,203 | 25,316 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 23,057 | |
Actual return on investments: | ||
Total return on investments | 1,814 | 2,379 |
Fair value of plan assets end of year | 23,980 | 23,057 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 2,862 | 2,716 |
Mississippi Power [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 1,154 | 1,231 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 77,723 | 69,657 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 44,341 | 37,196 |
Actual return on investments: | ||
Related to investments held at year end | 5,253 | 3,385 |
Related to investments sold during the year | 1,525 | 1,316 |
Total return on investments | 6,778 | 4,701 |
Purchases, sales, and settlements | 401 | 2,444 |
Fair value of plan assets end of year | 51,520 | 44,341 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Pension Plans [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 25,316 | 26,240 |
Actual return on investments: | ||
Related to investments held at year end | 3,269 | 378 |
Related to investments sold during the year | -745 | 2,300 |
Total return on investments | 2,524 | 2,678 |
Purchases, sales, and settlements | -1,637 | -3,602 |
Fair value of plan assets end of year | 26,203 | 25,316 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | ||
Actual return on investments: | ||
Fair value of plan assets end of year | 3,423 | 3,387 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Real Estate Investments [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 2,156 | 1,865 |
Actual return on investments: | ||
Related to investments held at year end | 28 | 158 |
Related to investments sold during the year | 67 | 64 |
Total return on investments | 95 | 222 |
Purchases, sales, and settlements | 18 | 69 |
Fair value of plan assets end of year | 2,269 | 2,156 |
Mississippi Power [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other Postretirement Benefits [Member] | Private Equity [Member] | ||
Changes in the fair value measurement of the Level 3 items in the pension plan assets | ||
Fair value of plan assets beginning of year | 1,231 | 1,293 |
Actual return on investments: | ||
Related to investments held at year end | 28 | 18 |
Related to investments sold during the year | -33 | 110 |
Total return on investments | -5 | 128 |
Purchases, sales, and settlements | -72 | -190 |
Fair value of plan assets end of year | $1,154 | $1,231 |
Retirement_Benefits_Textual_De
Retirement Benefits - Textual (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% | 3.84% |
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | |||
Total accumulated benefit obligation for the pension plans | $10,000,000,000 | $8,100,000,000 | ||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | |||
Pension Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 500,000,000 | |||
Expected postretirement trust contributions | 0 | |||
Discount rate on net periodic benefit costs | 4.17% | 5.02% | 4.26% | 4.98% |
Mortality Assumption Change | 636,000,000 | |||
Projected benefit obligations | 10,909,000,000 | 8,863,000,000 | 9,302,000,000 | |
Total matching contributions | 542,000,000 | 39,000,000 | ||
Other Postretirement Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected postretirement trust contributions | 19,000,000 | |||
Discount rate on net periodic benefit costs | 4.04% | 4.85% | 4.05% | 4.88% |
Mortality Assumption Change | 92,000,000 | |||
Projected benefit obligations | 1,986,000,000 | 1,682,000,000 | 1,872,000,000 | |
Total matching contributions | 39,000,000 | 39,000,000 | ||
Alabama Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% | 3.84% |
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | |||
Total accumulated benefit obligation for the pension plans | 2,400,000,000 | 1,900,000,000 | ||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | |||
Alabama Power [Member] | Pension Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Voluntary Contribution to Pension Plan | 0 | |||
Expected postretirement trust contributions | 0 | |||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% | 4.98% |
Mortality Assumption Change | 156,000,000 | |||
Projected benefit obligations | 2,592,000,000 | 2,112,000,000 | 2,218,000,000 | |
Total matching contributions | 11,000,000 | 9,000,000 | ||
Alabama Power [Member] | Other Postretirement Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected postretirement trust contributions | 2,000,000 | |||
Discount rate on net periodic benefit costs | 4.04% | 4.86% | 4.06% | 4.88% |
Mortality Assumption Change | 22,000,000 | |||
Projected benefit obligations | 503,000,000 | 431,000,000 | 490,000,000 | |
Total matching contributions | 4,000,000 | 7,000,000 | ||
Georgia Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected postretirement trust contributions | 17,000,000 | |||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% | 3.84% |
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | |||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | |||
Georgia Power [Member] | Pension Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 150,000,000 | |||
Expected postretirement trust contributions | 0 | |||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% | 4.98% |
Mortality Assumption Change | 226,000,000 | |||
Total accumulated benefit obligation for the pension plans | 3,500,000,000 | 2,900,000,000 | ||
Projected benefit obligations | 3,781,000,000 | 3,116,000,000 | 3,312,000,000 | |
Total matching contributions | 162,000,000 | 12,000,000 | ||
Georgia Power [Member] | Other Postretirement Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Discount rate on net periodic benefit costs | 4.03% | 4.85% | 4.04% | 4.87% |
Mortality Assumption Change | 46,000,000 | |||
Projected benefit obligations | 864,000,000 | 723,000,000 | 800,000,000 | |
Total matching contributions | 8,000,000 | 11,000,000 | ||
Gulf Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% | 3.84% |
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | |||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | |||
Gulf Power [Member] | Pension Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Discount rate on net periodic benefit costs | 4.18% | 5.02% | 4.27% | 4.98% |
Mortality Assumption Change | 29,600,000 | |||
Total accumulated benefit obligation for the pension plans | 438,000,000 | 353,000,000 | ||
Projected benefit obligations | 490,561,000 | 395,328,000 | 413,501,000 | |
Total matching contributions | 31,251,000 | 1,134,000 | ||
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected postretirement trust contributions | 0 | |||
Discount rate on net periodic benefit costs | 4.04% | 4.86% | 4.06% | 4.88% |
Mortality Assumption Change | 2,600,000 | |||
Projected benefit obligations | 78,501,000 | 68,579,000 | 75,395,000 | |
Total matching contributions | 2,846,000 | 2,381,000 | ||
Mississippi Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Annual salary increase on net periodic benefit costs | 3.59% | 3.59% | 3.59% | 3.84% |
Annual increase or decrease in assumed medical care cost trend rate | 1.00% | |||
Total accumulated benefit obligation for the pension plans | 462,000,000 | 370,000,000 | ||
Period over which company has elected to amortize changes in the market value of all plan assets | 5 years | |||
Total matching contributions | 4,600,000 | 4,100,000 | 3,900,000 | |
Mississippi Power [Member] | Pension Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 33,000,000 | |||
Discount rate on net periodic benefit costs | 4.17% | 5.01% | 4.26% | 4.98% |
Mortality Assumption Change | 30,200,000 | |||
Projected benefit obligations | 512,847,000 | 409,395,000 | 432,553,000 | |
Total matching contributions | 35,526,000 | 2,430,000 | ||
Mississippi Power [Member] | Other Postretirement Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Discount rate on net periodic benefit costs | 4.03% | 4.85% | 4.04% | 4.87% |
Mortality Assumption Change | 5,200,000 | |||
Projected benefit obligations | 95,655,000 | 80,940,000 | 91,783,000 | |
Total matching contributions | 3,413,000 | 2,562,000 | ||
Employee Saving Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Matching limit of contribution by employer | 85.00% | |||
Maximum limit of contribution of employees base salary | 6.00% | |||
Total matching contributions | 87,000,000 | 84,000,000 | 82,000,000 | |
Employee Saving Plan [Member] | Alabama Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Matching limit of contribution by employer | 85.00% | |||
Maximum limit of contribution of employees base salary | 6.00% | |||
Total matching contributions | 21,000,000 | 20,000,000 | 19,000,000 | |
Employee Saving Plan [Member] | Georgia Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Matching limit of contribution by employer | 85.00% | |||
Maximum limit of contribution of employees base salary | 6.00% | |||
Total matching contributions | 25,000,000 | 24,000,000 | 24,000,000 | |
Employee Saving Plan [Member] | Gulf Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Matching limit of contribution by employer | 85.00% | |||
Maximum limit of contribution of employees base salary | 6.00% | |||
Total matching contributions | 4,200,000 | 4,100,000 | 4,000,000 | |
Employee Saving Plan [Member] | Mississippi Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Matching limit of contribution by employer | 85.00% | |||
Maximum limit of contribution of employees base salary | 6.00% | |||
Qualified Pension Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | 10,300,000,000 | |||
Qualified Pension Plans [Member] | Alabama Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | 2,500,000,000 | |||
Qualified Pension Plans [Member] | Georgia Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | 3,600,000,000 | |||
Qualified Pension Plans [Member] | Gulf Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year | 30,000,000 | |||
Expected postretirement trust contributions | 0 | |||
Projected benefit obligations | 464,000,000 | |||
Qualified Pension Plans [Member] | Mississippi Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected postretirement trust contributions | 0 | |||
Projected benefit obligations | 481,000,000 | |||
Non Qualified Pension Plans [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | 617,000,000 | |||
Non Qualified Pension Plans [Member] | Alabama Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | 123,000,000 | |||
Non Qualified Pension Plans [Member] | Georgia Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | 165,000,000 | |||
Non Qualified Pension Plans [Member] | Gulf Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | 26,000,000 | |||
Non Qualified Pension Plans [Member] | Mississippi Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligations | $32,000,000 |
Acquisitions_Textual_Details
Acquisitions - Textual (Details) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | 0 Months Ended | ||||||
In Millions, unless otherwise specified | Apr. 17, 2014 | Dec. 31, 2014 | 22-May-14 | Nov. 26, 2014 | Nov. 06, 2014 | Dec. 31, 2014 | Apr. 23, 2013 | Feb. 19, 2015 | Feb. 24, 2015 | ||
MW | MW | ||||||||||
Business Acquisition [Line Items] | |||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | 100.00% | |||||||||
Southern Power [Member] | Adobe Solar LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | 90.00% | [1],[2] | 90.00% | [1],[2] | ||||||
Power of Solar Polycrystalline Silicon Facility | 20 | 20 | [1],[2] | 20 | [1],[2] | ||||||
Beginning Year of Output of Constructed Plant | 2014 | 2014 | [1],[2] | ||||||||
Life Output Of Plant | 20 years | 20 years | [1],[2] | ||||||||
Payments to Acquire Businesses, Gross | $96.20 | $96.20 | [1],[2] | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 83.5 | ||||||||||
Reimbursable Transmission Costs Receivable | 14.5 | ||||||||||
Purchased Power Agreement Intangible | 6.3 | ||||||||||
Business Combination, Bargain Purchase, Gain Recognized, Amount | 5.2 | ||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent | 2.9 | ||||||||||
Southern Power [Member] | Macho Springs, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | [1],[2] | 90.00% | [1],[2] | |||||||
Power of Solar Polycrystalline Silicon Facility | 50 | [1],[2] | 50 | 50 | [1],[2] | ||||||
Beginning Year of Output of Constructed Plant | 2014 | [1],[2] | |||||||||
Life Output Of Plant | 20 years | [1],[2] | 20 years | ||||||||
Payments to Acquire Businesses, Gross | 130 | [1],[2] | 130 | ||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 128 | ||||||||||
Reimbursable Transmission Costs Receivable | 1 | ||||||||||
Beginning Year Of Output Of Constructed Plant1 | 2014 | ||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets | 1 | ||||||||||
Southern Power [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 51.00% | [3],[4] | 51.00% | [3],[4] | |||||||
Power of Solar Polycrystalline Silicon Facility | 150 | [3],[4] | 150 | 150 | [3],[4] | ||||||
Beginning Year of Output of Constructed Plant | 2014 | [3],[4] | 2014 | ||||||||
Life Output Of Plant | 25 years | [3],[4] | 25 years | ||||||||
Payments to Acquire Businesses, Gross | 504.7 | [3],[4] | 504.7 | ||||||||
Southern Power [Member] | First Solar [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to Acquire Businesses, Gross | 127.9 | 599.3 | |||||||||
Southern Power [Member] | Campo Verde Solar LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 90.00% | [1],[2],[5] | 90.00% | [1],[2],[5] | |||||||
Power of Solar Polycrystalline Silicon Facility | 139 | [1],[2],[5] | 139 | [1],[2],[5] | 139 | ||||||
Beginning Year of Output of Constructed Plant | 2013 | [1],[2],[5] | 2013 | ||||||||
Life Output Of Plant | 20 years | [1],[2],[5] | 20 years | ||||||||
Payments to Acquire Businesses, Gross | 136.6 | [1],[2],[5] | 136.6 | ||||||||
Business Acquisition Cost of Acquired Entity Purchase Consideration Cash Will Be Paid | 355.5 | ||||||||||
First Solar [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to Acquire Businesses, Gross | 222.5 | ||||||||||
SG2 Holdings, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Payments to Acquire Businesses, Gross | 593.3 | 6 | |||||||||
SG2 Holdings, LLC [Member] | Solar Gen 2 Imperial Valley, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | 707.5 | 707.5 | |||||||||
Reimbursable Transmission Costs Receivable | 19.7 | 19.7 | |||||||||
Class A Membership Interest [Member] | Southern Power [Member] | SG2 Holdings, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | ||||||||||
Percentage Of Entitled Cash Distributions | 51.00% | ||||||||||
Class B Membership Interest [Member] | First Solar [Member] | SG2 Holdings, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Noncontrolling Interest, Ownership Percentage by Parent | 100.00% | ||||||||||
Percentage Of Entitled Cash Distributions | 49.00% | ||||||||||
Turner Renewable Energy [Member] | Southern Power [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 10.00% | 10.00% | |||||||||
Subsequent Event [Member] | Southern Power [Member] | Decatur County Solar Projects [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Beginning Year Of Output Of Constructed Plant1 | 2015 | ||||||||||
Subsequent Event [Member] | Southern Power [Member] | Decatur Parkway Solar Project, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Power of Solar Polycrystalline Silicon Facility | 80 | ||||||||||
Life Output Of Plant | 25 years | ||||||||||
Subsequent Event [Member] | Southern Power [Member] | Decatur County Solar Project, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Power of Solar Polycrystalline Silicon Facility | 19 | ||||||||||
Life Output Of Plant | 20 years | ||||||||||
Subsequent Event [Member] | Southern Power [Member] | Kay Wind, LLC [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Life Output Of Plant | 20 years | ||||||||||
Payments to Acquire Businesses, Gross | 492 | ||||||||||
Beginning Year Of Output Of Constructed Plant1 | 2015 | ||||||||||
Energy From Wind-Powered Generating Facilities | 299 | ||||||||||
Minimum [Member] | Subsequent Event [Member] | Southern Power [Member] | Decatur County Solar Projects [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Estimated Cost | 200 | ||||||||||
Maximum [Member] | Subsequent Event [Member] | Southern Power [Member] | Decatur County Solar Projects [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Estimated Cost | 220 | ||||||||||
[1] | Reflects 100% of the purchase price, including Turner Renewable Energy, LLC's 10% equity contribution. | ||||||||||
[2] | This acquisition was made by Southern Power and Turner Renewable Energy, LLC through Southern Turner Renewable Energy, LLC. | ||||||||||
[3] | Reflects Southern Power's portion of the purchase price. | ||||||||||
[4] | This acquisition was made by Southern Power through its subsidiaries Southern Renewable Partnerships, LLC and SG2 Holdings, LLC. SG2 Holdings, LLC is jointly-owned by Southern Power and First Solar, Inc. | ||||||||||
[5] | Under an engineering, procurement, and construction agreement, an additional $355.5 million was paid to a subsidiary of First Solar, Inc. to complete the construction of the solar facility. |
Contingencies_and_Regulatory_M2
Contingencies and Regulatory Matters - Current And Actual Cost Estimate (Details) (Mississippi Power [Member], USD $) | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2013 | Dec. 31, 2014 | ||
Loss Contingencies [Line Items] | |||
AFUDC Cost | $19,200,000 | ||
Total Kemper IGCC | 2,880,000,000 | ||
Loss Contingency, Estimate of Possible Loss | 2,050,000,000 | ||
Electricity Generation Plant, Non-Nuclear [Member] | |||
Loss Contingencies [Line Items] | |||
Plant Subject to Cost Cap | 2,400,000,000 | ||
Kemper IGCC [Member] | |||
Loss Contingencies [Line Items] | |||
Plant Subject to Cost Cap | 4,230,000,000 | [1] | |
Cost Of Lignite Mine And Equipment | 230,000,000 | ||
Cost Of CO2 Pipeline Facilities | 100,000,000 | ||
Cost Of AFUDC | 450,000,000 | [2],[3] | |
Combined Cycle And Related Assets Placed In Service, Incremental | 0 | [4] | |
Plant General Exceptions | 70,000,000 | ||
Plant Regulatory Asset | 120,000,000 | [5],[6] | |
Total Kemper IGCC | 5,200,000,000 | [5],[7] | |
Kemper IGCC [Member] | Project Estimate [Member] | |||
Loss Contingencies [Line Items] | |||
Plant Subject to Cost Cap | 2,400,000,000 | [7],[8] | |
Cost Of Lignite Mine And Equipment | 210,000,000 | [8] | |
Cost Of CO2 Pipeline Facilities | 140,000,000 | [8] | |
Cost Of AFUDC | 170,000,000 | [5],[8],[9] | |
Combined Cycle And Related Assets Placed In Service, Incremental | 0 | [4],[8] | |
Plant General Exceptions | 50,000,000 | [8] | |
Plant Regulatory Asset | 0 | [5],[6],[8] | |
Total Kemper IGCC | 2,970,000,000 | [5],[7],[8] | |
Kemper IGCC [Member] | Current Estimate [Member] | |||
Loss Contingencies [Line Items] | |||
Plant Subject to Cost Cap | 4,930,000,000 | [1] | |
Cost Of Lignite Mine And Equipment | 230,000,000 | ||
Cost Of CO2 Pipeline Facilities | 110,000,000 | ||
Cost Of AFUDC | 630,000,000 | [2],[3] | |
Combined Cycle And Related Assets Placed In Service, Incremental | 20,000,000 | [4] | |
Plant General Exceptions | 100,000,000 | ||
Plant Regulatory Asset | 180,000,000 | [5],[6] | |
Total Kemper IGCC | $6,200,000,000 | [1],[5],[7] | |
[1] | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014 that are subject to the $2.88 billion cost cap and excludes post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs b 2013 MPSC Rate Order" for additional information. | ||
[2] | Amounts in the Current Estimate reflect estimated costs through March 31, 2016. | ||
[3] | The Company's original estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC in 2012 as described in "Rate Recovery of Kemper IGCC Costs." | ||
[4] | Recovered through the ad valorem tax adjustment clause over a 12-month period beginning in April of the following year. See Note 3 under "Ad Valorem Tax Adjustment" for additional information. | ||
[5] | Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. | ||
[6] | Recorded as earned by employees and recovered as paid, generally within one year. This includes both vacation and banked holiday pay. | ||
[7] | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | ||
[8] | Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts, which generally do not exceed four years. Upon final settlement, costs are recovered through the ECM. | ||
[9] | Recorded and recovered (amortized) as approved by the Mississippi PSC. |
Contingencies_and_Regulatory_M3
Contingencies and Regulatory Matters - Textual (Details) (USD $) | 12 Months Ended | 3 Months Ended | 12 Months Ended | 24 Months Ended | 0 Months Ended | 1 Months Ended | 2 Months Ended | 84 Months Ended | 0 Months Ended | 1 Months Ended | 6 Months Ended | 12 Months Ended | 18 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 27 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | Dec. 31, 2010 | Dec. 31, 2014 | Sep. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2014 | Dec. 12, 2014 | Dec. 01, 2014 | Aug. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2004 | Jan. 01, 2014 | Dec. 31, 2013 | Jul. 31, 2013 | Jul. 31, 2007 | Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2008 | Jun. 30, 2014 | Jan. 29, 2015 | Aug. 01, 2014 | Apr. 01, 2013 | Mar. 19, 2013 | 20-May-14 | Mar. 31, 2013 | Jan. 31, 2013 | Feb. 28, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 10, 2013 | Jun. 30, 2012 | Dec. 31, 2011 | Sep. 30, 2012 | Dec. 09, 2014 | Aug. 05, 2014 | Jan. 01, 2013 | Jun. 01, 2012 | Jan. 01, 2012 | Jan. 01, 2011 | Jan. 01, 2015 | Jul. 01, 2014 | Oct. 31, 2014 | Oct. 20, 2014 | Oct. 09, 2014 | 6-May-14 | Jan. 31, 2014 | Jan. 04, 2014 | 31-May-13 | Feb. 01, 2015 | Oct. 22, 2014 | ||||||||||
Provisions | MW | MW | MW | MW | MW | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gain (Loss) Related to Litigation Settlement | ($202,000,000) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, lower range | 25,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, upper range | 37,500 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 346,000,000 | 346,000,000 | 207,000,000 | 207,000,000 | 346,000,000 | 346,000,000 | 207,000,000 | 346,000,000 | 346,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 2,201,000,000 | 2,201,000,000 | 2,018,000,000 | 2,018,000,000 | 2,201,000,000 | 2,201,000,000 | 2,018,000,000 | 2,201,000,000 | 1,757,000,000 | 1,757,000,000 | 2,201,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets | -4,664,000,000 | -4,664,000,000 | -2,624,000,000 | -2,624,000,000 | -4,664,000,000 | -4,664,000,000 | -2,624,000,000 | -4,664,000,000 | -4,664,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 170,000,000 | 170,000,000 | 7,000,000 | 7,000,000 | 170,000,000 | 170,000,000 | 7,000,000 | 170,000,000 | 70,000,000 | 70,000,000 | 170,000,000 | 120,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrued tax benefits on tax credits | 379,000,000 | 379,000,000 | 379,000,000 | 379,000,000 | 379,000,000 | 379,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 1,215,000,000 | 1,215,000,000 | 1,275,000,000 | 1,275,000,000 | 1,215,000,000 | 1,215,000,000 | 1,275,000,000 | 1,215,000,000 | 1,215,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount of Insurance Claim Received in Respect of Litigation Settlement | 15,000,000 | 25,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Legal Fee Related to Insurance Recoveries | 4,000,000 | 4,000,000 | 4,000,000 | 6,000,000 | 6,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Amount Received of Insurance Claim in Respect of Litigation Settlement | 11,000,000 | 11,000,000 | 11,000,000 | 19,000,000 | 19,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 4,334,000,000 | 4,334,000,000 | 2,495,000,000 | 2,495,000,000 | 4,334,000,000 | 4,334,000,000 | 2,495,000,000 | 4,334,000,000 | 4,334,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax Charge To Income | 868,000,000 | 70,000,000 | 418,000,000 | 380,000,000 | 40,000,000 | 150,000,000 | 450,000,000 | 540,000,000 | 1,200,000,000 | 2,050,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
After Tax Charge To Income | 536,000,000 | 43,200,000 | 258,100,000 | 234,700,000 | 24,700,000 | 92,600,000 | 277,900,000 | 333,500,000 | 729,000,000 | 1,260,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 160,000,000 | 160,000,000 | 160,000,000 | 160,000,000 | 160,000,000 | 160,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power and Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost of Project One | 660,000,000 | 660,000,000 | 660,000,000 | 660,000,000 | 660,000,000 | 660,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Designated Customer Value Benchmark Survey | 33.30% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, lower range | 25,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, upper range | 37,500 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear Fuel Disposal Costs [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Claims awarded to companies related to nuclear fuel disposal litigation | 26,000,000 | 17,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate Adjustment Period | 2 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum percentage of Rate RSE | 4.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum annual percentage of ratio rate | 5.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum projected retail return on common equity at which retail rates remain unchanged | 13.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum projected retail return on common equity at which retail rates remain unchanged | 14.50% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum increase in rate RSE | 5.00% | 4.51% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate RSE Increase | 3.49% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate RSE Increase Amount | 181,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Allowed Equity Ratio | 45.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number Of Provisions | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Adjusting Point Of Weighted Cost Of Equity | 5.98% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Basis Points | 0.07% | 0.07% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered certified PPA balance | 56,000,000 | 56,000,000 | 56,000,000 | 56,000,000 | 56,000,000 | 56,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved And Certified Energy From Wind-Powered Generating Facilities | 200 | 200 | 200 | 200 | 200 | 200 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number Of Wind Farms | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Rate Cnp Balance | 75,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered environmental clause | 49,000,000 | 49,000,000 | 49,000,000 | 49,000,000 | 49,000,000 | 49,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Which Deferred Regulatory Asset Account, Amortized | 3 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimate Amortization Of Regulatory Asset | 28,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of Regulatory Asset | 123,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liability Amortization | 120,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved billing rate under rate ECR up to (cents per KWH) | 0.0591 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Future stated rates under rate Ecr factor in terms of per units | 0.02681 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | 47,000,000 | 47,000,000 | 42,000,000 | 42,000,000 | 47,000,000 | 47,000,000 | 42,000,000 | 47,000,000 | 47,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred over recovered regulatory clause revenues | 47,000,000 | 47,000,000 | 15,000,000 | 15,000,000 | 47,000,000 | 47,000,000 | 15,000,000 | 47,000,000 | 47,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Period for recovery deferred storm-related operations and maintenance costs and any future reserve deficit | 24 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum total rate NDR charge per month, non-residential customer account | 10 | 10 | 10 | 10 | 10 | 10 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum total rate NDR charge per month, residential customer account | 5 | 5 | 5 | 5 | 5 | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Old Natural Disaster Reserve Authorized Limit | 75,000,000 | 75,000,000 | 75,000,000 | 75,000,000 | 75,000,000 | 75,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period To Amortize Expense | 3 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy From Wind-Powered Generating Facilities | 400 | 400 | 400 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Under Recovered Rate CNP Balance | 1.50% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 84,000,000 | 84,000,000 | 54,000,000 | 54,000,000 | 84,000,000 | 84,000,000 | 54,000,000 | 84,000,000 | 84,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 14.00% | 14.00% | 14.00% | 14.00% | 14.00% | 14.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 829,000,000 | 829,000,000 | 730,000,000 | 730,000,000 | 829,000,000 | 829,000,000 | 730,000,000 | 829,000,000 | 589,000,000 | 589,000,000 | 829,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets | -738,000,000 | -738,000,000 | -92,000,000 | -92,000,000 | -738,000,000 | -738,000,000 | -92,000,000 | -738,000,000 | -738,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 0 | 0 | 0 | 31,000,000 | 31,000,000 | 32,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generating Units, Capacity | 1,000 | 1,000 | 1,000 | 1,000 | 1,000 | 1,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 744,000,000 | 744,000,000 | 828,000,000 | 828,000,000 | 744,000,000 | 744,000,000 | 828,000,000 | 744,000,000 | 744,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-nuclear Outage Costs | 95,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Compliance And Pension Costs | 28,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 1,063,000,000 | 1,063,000,000 | 645,000,000 | 645,000,000 | 1,063,000,000 | 1,063,000,000 | 645,000,000 | 1,063,000,000 | 1,063,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted Cost Of Equity | 5.75% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted Cost Of Equity | 6.21% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Fuel Recovery Clause [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred over recovered regulatory clause revenues | 47,000,000 | 47,000,000 | 47,000,000 | 47,000,000 | 47,000,000 | 47,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Non-Environmental Federal Mandates [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferral of maintenance costs | 50,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Current Rate Stabilization And Equalization [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted Cost Of Equity | 5.85% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Current Rate Stabilization And Equalization [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted Cost Of Equity | 6.53% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Adjusting Point Of Weighted Cost Of Equity | 6.19% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Gorgas Units 6 and 7 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | 200 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Greene County Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | 300 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Gorgas [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generating Units, Capacity | 12,200 | 12,200 | 12,200 | 12,200 | 12,200 | 12,200 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Barry Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | 250 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Barry Unit 3 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | 225 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alabama Power [Member] | Plant Farley [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Recovery Amount From Customers Associated With Permanent Disposal Of Nuclear Waste | 8,000,000 | 8,000,000 | 8,000,000 | 8,000,000 | 8,000,000 | 8,000,000 | 14,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase In NCCR Tariff | 60,000,000 | 50,000,000 | 35,000,000 | 223,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number of Plants For Decertification | 16 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, lower range | 25,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, upper range | 37,500 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | 22,000,000 | 22,000,000 | 22,000,000 | 22,000,000 | 22,000,000 | 22,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear Fuel Disposal Costs [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Claims awarded to companies related to nuclear fuel disposal litigation | 18,000,000 | 27,000,000 | 27,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Portion of Actual Earnings Above Approved ROE Band Retained by Subsidiary Company | 33.33% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Portion of Actual Earnings Above Approved ROE Band Refunded to Customers | 66.67% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liability Amortization | 31,000,000 | 14,000,000 | 31,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 10.95% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Test Period For PSC | 90 days | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Included In Request by Subsidiaries For Decertification Of Units | 2,093 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period for Environmental Construction | 9 years | 9 years | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 136,000,000 | 136,000,000 | 106,000,000 | 106,000,000 | 136,000,000 | 136,000,000 | 106,000,000 | 136,000,000 | 136,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | 4,400,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amendment To Estimated In-service Capital Cost | 4,800,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue Subject To Refund | 13,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 1,255,000,000 | 1,255,000,000 | 1,222,000,000 | 1,222,000,000 | 1,255,000,000 | 1,255,000,000 | 1,222,000,000 | 1,255,000,000 | 1,105,000,000 | 1,105,000,000 | 1,255,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets | -2,529,000,000 | -2,529,000,000 | -1,886,000,000 | -1,886,000,000 | -2,529,000,000 | -2,529,000,000 | -1,886,000,000 | -2,529,000,000 | -2,529,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 0 | 0 | 0 | 23,000,000 | 23,000,000 | 47,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 46,000,000 | 46,000,000 | 43,000,000 | 43,000,000 | 46,000,000 | 46,000,000 | 43,000,000 | 46,000,000 | 46,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Extension Period For Mercury And Air Toxics Standards | 1 year | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil Penalties Per Violation Rate | 37,500 | 37,500 | 37,500 | 37,500 | 37,500 | 37,500 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number of Times of Punitive Damages in Comparison to Cost Incurred by Environmental Protection Agency | 3 | 3 | 3 | 3 | 3 | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number Of Intervenors Approved ARP | 11 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Number of Intervenors | 13 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Tariff Rate One | 80,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Increase In ECCR Tariff | 25,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Demand Side Management Tariffs | 1,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Increase In Municipal Franchise Fee Tariff | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Base Revenue Under Alternative Rate Plan | 110,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved Increase in Annual Billing Based on Fuel Cost Recovery Rate | 122,000,000 | 567,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Adjustment To FuelCost Recovery Rate If Under Recovered Fuel Balance Exceeds Budget Thereafter | 200,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Required Period For Options And Hedges | 24 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over Recovered Fuel Balance | 199,000,000 | 199,000,000 | 58,000,000 | 58,000,000 | 199,000,000 | 199,000,000 | 58,000,000 | 199,000,000 | 199,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrual Under Alternate Rate Plan | 30,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 1,753,000,000 | 1,753,000,000 | 1,113,000,000 | 1,113,000,000 | 1,753,000,000 | 1,753,000,000 | 1,113,000,000 | 1,753,000,000 | 1,753,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generating Capacity in Mega Watts Under Consortium Agreement | 1,100 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional Construction Capital Costs | 200,000,000 | 2,800,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of Proportionate Share Owed in Consortium Agreement | 45.70% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Adjustment to Contract Price Related to Issues that May Impact Project Budget and Schedule | 425,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) In Projected Certified Construction Capital Costs | 5.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase In NCCR Tariff | 27,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue to be Received from Increase in Base Rate Two | 136,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Increase In Municipal Franchise Fee Tariff | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Tariff Rate Two | 107,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Increase In ECCR Tariff One | 23,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Increase In Demand Side Management Tariffs | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Delay Of Estimated In-service Date | 18 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 12.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional Construction Capital Costs | 114,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Damages In Connection With Counterclaim | 113,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Property Damage Reserves Liability [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferral of maintenance costs | 98,000,000 | 98,000,000 | 37,000,000 | 37,000,000 | 98,000,000 | 98,000,000 | 37,000,000 | 98,000,000 | 98,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | 30,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 68,000,000 | 68,000,000 | 7,000,000 | 7,000,000 | 68,000,000 | 68,000,000 | 7,000,000 | 68,000,000 | 68,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Storm Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferral of maintenance costs | 98,000,000 | 98,000,000 | 37,000,000 | 37,000,000 | 98,000,000 | 98,000,000 | 37,000,000 | 98,000,000 | 98,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | 5,000,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Operational Readiness Costs | 10,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Financing Costs | 30,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction Financing Costs | 2,500,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Branch Units Three And Four [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | 1,016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Yates [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | 579 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant McManus [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | 122 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Branch Unit One [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | 250 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Kraft [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | 316 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Branch Unit Two [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Units Approved For Decertification Of Units | 319 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Georgia Power [Member] | Plant Mitchell [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Of Small Power Production Facility | 155 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, lower range | 25,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, upper range | 37,500 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost of Services, Environmental Remediation | 500,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
FERC Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Annual Base Wholesale Revenues | 22,600,000 | 22,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Over Which Annual Revenue Will Increase Under Tariff | 12 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Base Rate Under Cost Based Electric Tariff Due to Settlement | 24,200,000 | 10,100,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Anticipates of elimination adjustment will result in additional revenues | 3,300,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual PEP Lookback Refund To Customers | 4,700,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | 14,500,000 | 14,500,000 | 14,500,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 72,840,000 | 72,840,000 | 48,583,000 | 48,583,000 | 72,840,000 | 72,840,000 | 48,583,000 | 72,840,000 | 72,840,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Required Customers For Energy Efficiency Programs | 25,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Required Period For Filing Quick Start Plans | 6 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Of PSC Retail Rate Increase | 0.38% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Project expenditures, cumulative | 518,200,000 | 518,200,000 | 518,200,000 | 518,200,000 | 518,200,000 | 518,200,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Project expenditures, cumulative, proportionate share | 263,400,000 | 263,400,000 | 263,400,000 | 263,400,000 | 263,400,000 | 263,400,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
AFUDC Cost | 19,200,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSC Retail Rate Increase | 6,700,000 | 3,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Plant capacity under coal gasification combined cycle technology in Mega Watts | 582 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
New Co2 Pipeline Infrastructure | 61 | 61 | 61 | 61 | 61 | 61 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs Related to Grant Funding | 245,300,000 | 245,300,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum cap construction cost | 2,880,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate Recovery | 257,200,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquisition Period For SMEPA | 180 days | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | 3,040,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Loss Contingency, Estimate of Possible Loss | 2,050,000,000 | 2,050,000,000 | 2,050,000,000 | 2,050,000,000 | 2,050,000,000 | 2,050,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Property And Investments | 1,800,000 | 1,800,000 | 1,800,000 | 1,800,000 | 1,800,000 | 1,800,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prepaid Supplies | 32,500,000 | 32,500,000 | 32,500,000 | 32,500,000 | 32,500,000 | 32,500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost deferred in other regulatory assets | 147,700,000 | 147,700,000 | 147,700,000 | 147,700,000 | 147,700,000 | 147,700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other deferred charges and assets | 11,600,000 | 11,600,000 | 11,600,000 | 11,600,000 | 11,600,000 | 11,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 48,248,000 | 48,248,000 | 41,910,000 | 41,910,000 | 48,248,000 | 48,248,000 | 41,910,000 | 48,248,000 | 42,115,000 | 42,115,000 | 48,248,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Previously expensed | 1,100,000 | 1,100,000 | 1,100,000 | 1,100,000 | 1,100,000 | 1,100,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Lignite Mining Costs | 44,700,000 | 44,700,000 | 44,700,000 | 44,700,000 | 44,700,000 | 44,700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase Retail Rates In Year One | 15.00% | 15.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase Retail Rates In Year Two | 3.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement Collection Amount To Mitigate Rate Impact Year Two | 156,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets | -171,764,000 | -171,764,000 | -66,604,000 | -66,604,000 | -171,764,000 | -171,764,000 | -66,604,000 | -171,764,000 | -171,764,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities Collected | 257,200,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 164,821,000 | 164,821,000 | 3,840,000 | 3,840,000 | 164,821,000 | 164,821,000 | 3,840,000 | 164,821,000 | 5,755,000 | 5,755,000 | 164,821,000 | 4,964,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Reduced Percentage Interest Transferred under Asset Purchase Agreement | 15.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Revenues Under Power Supply Agreement | 16,700,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term of management fee contract | 40 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of Carbon dioxide captured from project by purchase Denbury | 70.00% | 70.00% | 70.00% | 70.00% | 70.00% | 70.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of contract to purchase carbon dioxide from Kemper IGCC | 30.00% | 30.00% | 30.00% | 30.00% | 30.00% | 30.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase of interest in plant | 17.50% | 17.50% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deposit Received | 150,000,000 | 150,000,000 | 50,000,000 | 50,000,000 | 75,000,000 | 75,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Period to Refund Deposit upon Termination of Asset Purchase Agreement | 15 days | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Tax credits (Phase II) | 279,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accrued tax benefits on tax credits | 276,400,000 | 276,400,000 | 276,400,000 | 276,400,000 | 276,400,000 | 276,400,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Tax Credit Carryforward Utilized | 210,000,000 | 210,000,000 | 210,000,000 | 210,000,000 | 210,000,000 | 210,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum percentage of carbon dioxide that must be capture and sequester to remain eligible for the phase II tax credits | 65.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prudence Review Of Plant Cost Within Settlement Agreement | 3 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization Period For Construction Project | 40 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual PEP Filing Rate Increase | 1.90% | 1.90% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual PEP Filing Rate Increase Amount | 15,300,000 | 15,300,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost of Project, Proportionate Share | 330,000,000 | 330,000,000 | 330,000,000 | 330,000,000 | 330,000,000 | 330,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 10.13% | 10.13% | 9.93% | 9.93% | 10.13% | 10.13% | 9.93% | 10.13% | 9.97% | 9.97% | 10.13% | 7.13% | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 165,999,000 | 165,999,000 | 156,683,000 | 156,683,000 | 165,999,000 | 165,999,000 | 156,683,000 | 165,999,000 | 165,999,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Bonus Depreciation for Property Acquired | 50.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Grant For Energy Efficiency And Renewable Program | 15,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Of Grant For Energy Efficiency and Renewable Program | 15 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Conservation Fund | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 385,410,000 | 385,410,000 | 200,620,000 | 200,620,000 | 385,410,000 | 385,410,000 | 200,620,000 | 385,410,000 | 385,410,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proposed Change in Annual Revenues | 1,100,000 | 100,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Daniel Units 1 and 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period For Quick Start Plans To Be In Effect | 2 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period For Quick Start Plans To Be In Effect | 3 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Retail [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proposed Change in Annual Revenues | 7,900,000 | 7,900,000 | 7,900,000 | 7,900,000 | 7,900,000 | 7,900,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Fuel Cost | 2,500,000 | 2,500,000 | 2,500,000 | 2,500,000 | 2,500,000 | 2,500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | MRA Revenue [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | 7,300,000 | 7,300,000 | 7,300,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount Of Over Recovered Emissions Allowance Cost | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | 300,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount Of Under Recovered Emissions Allowance Cost | 3,800,000 | 3,800,000 | 3,800,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | MB Revenue [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over recovered fuel cost | 200,000 | 200,000 | 300,000 | 300,000 | 200,000 | 200,000 | 300,000 | 200,000 | 200,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost of Project One | 660,000,000 | 660,000,000 | 660,000,000 | 660,000,000 | 660,000,000 | 660,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Gulf Power [Member] | Plant Daniel Units 1 and 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generating Units, Capacity | 1,000 | 1,000 | 1,000 | 1,000 | 1,000 | 1,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Mirror Construction Work In Progress [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets | 270,779,000 | [1] | 270,779,000 | [1] | 90,524,000 | [1] | 90,524,000 | [1] | 270,779,000 | [1] | 270,779,000 | [1] | 90,524,000 | [1] | 270,779,000 | [1] | 270,779,000 | [1] | ||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Electricity Generation Plant, Non-Nuclear [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost | 2,400,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Alternate Financing | 1,000,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferral of maintenance costs | 147,700,000 | 147,700,000 | 147,700,000 | 147,700,000 | 147,700,000 | 147,700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected Balance Of Regulatory Assets | 269,800,000 | 269,800,000 | 269,800,000 | 269,800,000 | 269,800,000 | 269,800,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost | 4,230,000,000 | [2] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum cap construction cost | 5,200,000,000 | [3],[4] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Charge Of Allowance For Equity Funds Used During Construction | 13,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Monthly Cost Regulatory Assets Deferred | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 23,600,000 | 23,600,000 | 23,600,000 | 23,600,000 | 23,600,000 | 23,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pre-Tax Charge To Income | 70,000,000 | 418,000,000 | 380,000,000 | 40,000,000 | 150,000,000 | 450,000,000 | 462,000,000 | 1,100,000,000 | 78,000,000 | 78,000,000 | 2,050,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
After Tax Charge To Income | 43,200,000 | 258,100,000 | 234,700,000 | 24,700,000 | 92,600,000 | 277,900,000 | 285,300,000 | 680,500,000 | 48,200,000 | 48,200,000 | 1,260,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generating Units, Capacity | 75 | 75 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Positive Impact From Bonus Depreciation | 130,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | 25,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Minimum [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Positive Impact From Bonus Depreciation | 45,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated In-service Capital Cost | 30,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | Maximum [Member] | Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Positive Impact From Bonus Depreciation | 50,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Mine [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term of management fee contract | 40 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Sweatt Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Unit Conversion To Non-fossil Fuel Source | 80 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Watson Units 4 And 5 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Unit Conversion To Non-fossil Fuel Source | 750 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Greene County Units 1 And 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 5,600,000 | 5,600,000 | 5,600,000 | 5,600,000 | 5,600,000 | 5,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity Unit Conversion To Non-fossil Fuel Source | 200 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 5,600,000 | 5,600,000 | 5,600,000 | 5,600,000 | 5,600,000 | 5,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Mississippi Power [Member] | Plant Watson [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Costs included in CWIP | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, lower range | 25,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Civil penalties under Clean Air Act per day, upper range | 37,500 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | 48,300,000 | 48,300,000 | 48,300,000 | 48,300,000 | 48,300,000 | 48,300,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Of Treasury Yield Rate | 30 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Basis Points | 0.25% | 0.25% | 0.25% | 0.25% | 0.25% | 0.25% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 10.25% | 10.25% | 10.25% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Current | 74,242,000 | 74,242,000 | 18,536,000 | 18,536,000 | 74,242,000 | 74,242,000 | 18,536,000 | 74,242,000 | 74,242,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation | 16,711,000 | 16,711,000 | 16,184,000 | 16,184,000 | 16,711,000 | 16,711,000 | 16,184,000 | 16,711,000 | 16,055,000 | 16,055,000 | 16,711,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Regulatory Assets | -319,644,000 | -319,644,000 | -160,224,000 | -160,224,000 | -319,644,000 | -319,644,000 | -160,224,000 | -319,644,000 | -319,644,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Tax Benefits | 46,000 | 46,000 | 45,000 | 45,000 | 46,000 | 46,000 | 45,000 | 46,000 | 5,007,000 | 5,007,000 | 46,000 | 2,892,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost of Project One | 330,000,000 | 330,000,000 | 330,000,000 | 330,000,000 | 330,000,000 | 330,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Base Revenue In Year One | 35,000,000 | 35,000,000 | 35,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Base Revenue In Year Two | 20,000,000 | 20,000,000 | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period of Treasury Rate Above Basis Points | 6 months | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 234,587,000 | 234,587,000 | 228,148,000 | 228,148,000 | 234,587,000 | 234,587,000 | 228,148,000 | 234,587,000 | 234,587,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reduction In Depreciation Expense | 8,400,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate Increase (Decrease) | 41,200,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Power Over (Under) Recovered Balance Percentage | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period of Establishment of Conservation Goals, in Years | 5 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Period Numeric Conservation Goals Cover, in Years | 10 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets Deferred | 416,028,000 | 416,028,000 | 340,415,000 | 340,415,000 | 416,028,000 | 416,028,000 | 340,415,000 | 416,028,000 | 416,028,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | Plant Daniel Units 1 and 2 [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent ownership | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | 50.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generating Units, Capacity | 1,000 | 1,000 | 1,000 | 1,000 | 1,000 | 1,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percent Of Basis Points | 0.75% | 0.75% | 0.75% | 0.75% | 0.75% | 0.75% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 9.25% | 9.25% | 9.25% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected fuel cost over or under recovery threshold, as a percentage of projected fuel revenue | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gulf Power [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Rate of Return on Common Equity | 11.25% | 11.25% | 11.25% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Regulatory Clause Revenues and Other Current Liabilities [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | 4,500,000 | 4,500,000 | 4,500,000 | 4,500,000 | 4,500,000 | 4,500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Regulatory Assets, Deferred and Other Deferred Credits and Liabilities [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental remediation liability | 43,700,000 | 43,700,000 | 43,700,000 | 43,700,000 | 43,700,000 | 43,700,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other regulatory liabilities current [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered fuel balance | 21,000,000 | 21,000,000 | 21,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Clause Revenues, under-recovered [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered fuel balance | 39,900,000 | 39,900,000 | 39,900,000 | 39,900,000 | 39,900,000 | 39,900,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Power, Over Under Recovered Balance | 300,000 | 300,000 | 2,800,000 | 2,800,000 | 300,000 | 300,000 | 2,800,000 | 300,000 | 300,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Environmental Cost | 9,800,000 | 9,800,000 | 14,400,000 | 14,400,000 | 9,800,000 | 9,800,000 | 14,400,000 | 9,800,000 | 9,800,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Energy Conservation Costs | 2,600,000 | 2,600,000 | 2,600,000 | 2,600,000 | 2,600,000 | 2,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Over Recovered Energy Conservation Costs | 7,000,000 | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Regulatory Clause Revenues [Member] | Alabama Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered certified PPA balance | 27,000,000 | 27,000,000 | 27,000,000 | 27,000,000 | 27,000,000 | 27,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered environmental clause | 47,000,000 | 47,000,000 | 47,000,000 | 47,000,000 | 47,000,000 | 47,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Under Recovered Regulatory Clause Revenues [Member] | Alabama Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Regulatory Matters [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered certified PPA balance | 29,000,000 | 29,000,000 | 29,000,000 | 29,000,000 | 29,000,000 | 29,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under recovered environmental clause | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prime Rate [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.79% | 3.79% | 3.79% | 3.79% | 3.79% | 3.79% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement [Member] | Mississippi Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Income | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Settlement Agreement [Member] | Gulf Power [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Cost of Removal Obligations | 62,500,000 | 62,500,000 | 62,500,000 | 62,500,000 | 62,500,000 | 62,500,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Current Estimate [Member] | Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Integrated Coal Gasification Combined Cycle [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated Cost | 4,930,000,000 | [2] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum cap construction cost | $6,200,000,000 | [2],[3],[4] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[1] | For additional information, see Note 3 under "Integrated Coal Gasification Combined Cycle b Rate Recovery of Kemper IGCC Costs b Regulatory Assets and Liabilities." | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014 that are subject to the $2.88 billion cost cap and excludes post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs b 2013 MPSC Rate Order" for additional information. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | Recovered and amortized over the average remaining service period which may range up to 14 years. See Note 2 for additional information. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | Asset retirement and removal assets and liabilities and deferred income tax assets are recovered, and removal assets and deferred income tax liabilities are amortized over the related property lives, which may range up to 49 years. Asset retirement and removal assets and liabilities will be settled and trued up following completion of the related activities. |
Joint_Ownership_Agreements_Det
Joint Ownership Agreements (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Aug. 31, 2014 | ||
MW | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Short-term Debt | $803,000,000 | $1,482,000,000 | |||
Plant acquisition adjustment | 123,000,000 | 123,000,000 | |||
Plant Vogtle (nuclear) Units 1 and 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 45.70% | ||||
Plant in Service | 3,420,000,000 | ||||
Accumulated Depreciation | 2,059,000,000 | ||||
Construction Work in Progress | 0 | ||||
Plant Hatch (nuclear) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 50.10% | ||||
Plant in Service | 1,117,000,000 | ||||
Accumulated Depreciation | 559,000,000 | ||||
Construction Work in Progress | 0 | ||||
Plant Miller (coal) Units 1 and 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 91.80% | ||||
Plant in Service | 1,512,000,000 | ||||
Accumulated Depreciation | 561,000,000 | ||||
Construction Work in Progress | 0 | ||||
Plant Scherer (coal) Units 1 and 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 8.40% | ||||
Plant in Service | 254,000,000 | ||||
Accumulated Depreciation | 83,000,000 | ||||
Construction Work in Progress | 0 | ||||
Plant Wansley (coal) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 53.50% | ||||
Plant in Service | 856,000,000 | ||||
Accumulated Depreciation | 278,000,000 | ||||
Construction Work in Progress | 0 | ||||
Rocky Mountain (pumped storage) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 25.40% | ||||
Plant in Service | 182,000,000 | ||||
Accumulated Depreciation | 124,000,000 | ||||
Construction Work in Progress | 0 | ||||
Intercession City (combustion turbine) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 33.30% | ||||
Plant in Service | 14,000,000 | ||||
Accumulated Depreciation | 5,000,000 | ||||
Construction Work in Progress | 0 | ||||
Plant Stanton (combined cycle) Unit A [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 65.00% | ||||
Plant in Service | 157,000,000 | ||||
Accumulated Depreciation | 47,000,000 | ||||
Construction Work in Progress | 0 | ||||
Alabama Power [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 14.00% | ||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 1,000 | ||||
Jointly Owned Affiliate Equity | 106,000,000 | ||||
Jointly Owned Affiliate Long Term Debt | 125,000,000 | ||||
Jointly Owned Affiliate Long Term Debt Annual Interest Requirement | 3,000,000 | ||||
Dividends paid by equity method investment | 3,000,000 | 7,000,000 | 14,000,000 | ||
Ownership percentage, equity method investment | 50.00% | ||||
Plant acquisition adjustment | 12,000,000 | 12,000,000 | |||
Alabama Power [Member] | SEGCO [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 1,020 | ||||
Share Of Purchased Power | 84,000,000 | 88,000,000 | 109,000,000 | ||
Unconditional guarantee to pay outstanding pollution control revenue bond principal | 25,000,000 | ||||
Guarantee of unsecured senior notes | 50,000,000 | ||||
Alabama Power [Member] | SEGCO [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Short-term Debt | 42,000,000 | ||||
Alabama Power [Member] | Senior notes due December 1, 2018 [Member] | SEGCO [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Guarantee of unsecured senior notes | 100,000,000 | ||||
Alabama Power [Member] | Natural Gas Pipeline [Member] | |||||
Jointly owned utility plant interests | |||||
Construction Work in Progress | 15,000,000 | ||||
Alabama Power [Member] | Plant Miller (coal) Units 1 and 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 91.84% | [1] | |||
Plant in Service | 1,512,000,000 | ||||
Accumulated Depreciation | 561,000,000 | ||||
Construction Work in Progress | 14,000,000 | ||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 1,320 | ||||
Alabama Power [Member] | SEGCO [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 86.00% | ||||
Alabama Power [Member] | Greene County [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 60.00% | [2] | |||
Plant in Service | 164,000,000 | ||||
Accumulated Depreciation | 96,000,000 | ||||
Construction Work in Progress | 1,000,000 | ||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 500 | ||||
Georgia Power [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Short-term Debt | 156,000,000 | 1,047,000,000 | |||
Plant acquisition adjustment | 28,000,000 | 28,000,000 | |||
Georgia Power [Member] | SEGCO [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Share Of Purchased Power | 84,000,000 | 91,000,000 | |||
Georgia Power [Member] | Purchased Power from Affiliates [Member] | SEGCO [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Share Of Purchased Power | 107,000,000 | ||||
Georgia Power [Member] | Alabama Power [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 1,020 | ||||
Georgia Power [Member] | Plant Vogtle (nuclear) Units 1 and 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 45.70% | ||||
Plant in Service | 3,420,000,000 | ||||
Accumulated Depreciation | 2,059,000,000 | ||||
Construction Work in Progress | 46,000,000 | ||||
Georgia Power [Member] | Plant Hatch (nuclear) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 50.10% | ||||
Plant in Service | 1,117,000,000 | ||||
Accumulated Depreciation | 559,000,000 | ||||
Construction Work in Progress | 66,000,000 | ||||
Georgia Power [Member] | Plant Scherer (coal) Units 1 and 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 8.40% | ||||
Plant in Service | 254,000,000 | ||||
Accumulated Depreciation | 83,000,000 | ||||
Construction Work in Progress | 1,000,000 | ||||
Georgia Power [Member] | Plant Wansley (coal) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 53.50% | ||||
Plant in Service | 856,000,000 | ||||
Accumulated Depreciation | 278,000,000 | ||||
Construction Work in Progress | 15,000,000 | ||||
Georgia Power [Member] | Rocky Mountain (pumped storage) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 25.40% | ||||
Plant in Service | 182,000,000 | ||||
Accumulated Depreciation | 124,000,000 | ||||
Construction Work in Progress | 2,000,000 | ||||
Georgia Power [Member] | Intercession City (combustion turbine) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 33.30% | ||||
Plant in Service | 14,000,000 | ||||
Accumulated Depreciation | 5,000,000 | ||||
Construction Work in Progress | 0 | ||||
Georgia Power [Member] | Vogtle Units 3 and 4 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 45.70% | ||||
Georgia Power [Member] | Plant Scherer Unit 3 (coal) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 75.00% | ||||
Plant in Service | 1,172,000,000 | ||||
Accumulated Depreciation | 417,000,000 | ||||
Construction Work in Progress | 10,000,000 | ||||
Gulf Power [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Short-term Debt | 109,977,000 | 135,878,000 | |||
Plant acquisition adjustment | 1,776,000 | 2,031,000 | |||
Gulf Power [Member] | Plant Scherer Unit 3 (coal) [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 25.00% | ||||
Plant in Service | 387,511,000 | [3] | |||
Accumulated Depreciation | 130,069,000 | ||||
Construction Work in Progress | 2,912,000 | ||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 818 | ||||
Plant acquisition adjustment | 1,800,000 | ||||
Gulf Power [Member] | Plant Daniel Units 1 &2 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 50.00% | ||||
Plant in Service | 285,834,000 | ||||
Accumulated Depreciation | 177,304,000 | ||||
Construction Work in Progress | 286,343,000 | ||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 1,000 | ||||
Mississippi Power [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Plant acquisition adjustment | 81,412,000 | 81,412,000 | |||
Mississippi Power [Member] | Greene County [Member] | |||||
Jointly owned utility plant interests | |||||
Construction Work in Progress | 5,600,000 | ||||
Mississippi Power [Member] | Greene County [Member] | Alabama Power [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 40.00% | ||||
Plant in Service | 102,384,000 | ||||
Accumulated Depreciation | 51,911,000 | ||||
Construction Work in Progress | 902,000 | ||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 500 | ||||
Mississippi Power [Member] | Plant Daniel Units 1 &2 2 [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 50.00% | ||||
Mississippi Power [Member] | Plant Daniel Units 1 &2 2 [Member] | Gulf Power [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 50.00% | ||||
Plant in Service | 299,440,000 | ||||
Accumulated Depreciation | 155,606,000 | ||||
Construction Work in Progress | 286,240,000 | ||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 1,000 | ||||
Southern Power [Member] | |||||
Joint Ownership Agreements (Textual) [Abstract] | |||||
Total Megawatt Capacity | 659 | ||||
Short-term Debt | 194,917,000 | 0 | |||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | |||||
Jointly owned utility plant interests | |||||
Plant in Service | 156,500,000 | ||||
Accumulated Depreciation | $46,600,000 | ||||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Southern Power [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 65.00% | ||||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Orlando Utilities Commission [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 28.00% | ||||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Florida Municipal Power Agency [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 3.50% | ||||
Southern Power [Member] | Plant Stanton (combined cycle) Unit A [Member] | Kissimmee Utility Authority [Member] | |||||
Jointly owned utility plant interests | |||||
Percent Ownership | 3.50% | ||||
[1] | Jointly owned with PowerSouth Energy Cooperative, Inc. | ||||
[2] | Jointly owned with an affiliate, Mississippi Power. | ||||
[3] | Includes net plant acquisition adjustment of $1.8 million. |
Income_Taxes_Current_and_Defer
Income Taxes - Current and Deferred Income Tax Provisions (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Federal - | |||
Current | $175,000 | $363,000 | $177,000 |
Deferred | 695,000 | 386,000 | 1,011,000 |
Total federal taxes | 870,000 | 749,000 | 1,188,000 |
State - | |||
Current | 93,000 | -10,000 | 61,000 |
Deferred | 14,000 | 110,000 | 85,000 |
Total state taxes | 107,000 | 100,000 | 146,000 |
Income taxes | 977,000 | 849,000 | 1,334,000 |
Alabama Power [Member] | |||
Federal - | |||
Current | 198,000 | 243,000 | 262,000 |
Deferred | 225,000 | 160,000 | 137,000 |
Total federal taxes | 423,000 | 403,000 | 399,000 |
State - | |||
Current | 44,000 | 36,000 | 51,000 |
Deferred | 45,000 | 39,000 | 27,000 |
Total state taxes | 89,000 | 75,000 | 78,000 |
Income taxes | 512,000 | 478,000 | 477,000 |
Georgia Power [Member] | |||
Federal - | |||
Current | 295,000 | 277,000 | 273,000 |
Deferred | 366,000 | 374,000 | 370,000 |
Total federal taxes | 661,000 | 651,000 | 643,000 |
State - | |||
Current | 82,000 | -30,000 | 38,000 |
Deferred | -14,000 | 102,000 | 7,000 |
Total state taxes | 68,000 | 72,000 | 45,000 |
Income taxes | 729,000 | 723,000 | 688,000 |
Gulf Power [Member] | |||
Federal - | |||
Current | 22,771 | 5,009 | -92,610 |
Deferred | 52,602 | 63,134 | 161,096 |
Total federal taxes | 75,373 | 68,143 | 68,486 |
State - | |||
Current | -39 | -2,410 | -2,484 |
Deferred | 12,728 | 13,935 | 13,209 |
Total state taxes | 12,689 | 11,525 | 10,725 |
Income taxes | 88,062 | 79,668 | 79,211 |
Mississippi Power [Member] | |||
Federal - | |||
Current | -431,077 | 23,345 | 1,212 |
Deferred | 183,461 | -342,870 | 16,994 |
Total federal taxes | -247,616 | -319,525 | 18,206 |
State - | |||
Current | 455 | 5,219 | 1,656 |
Deferred | -38,044 | -53,529 | 694 |
Total state taxes | -37,589 | -48,310 | 2,350 |
Income taxes | -285,205 | -367,835 | 20,556 |
Southern Power [Member] | |||
Federal - | |||
Current | 178,600 | -120,200 | -133,100 |
Deferred | -166,000 | 158,700 | 210,400 |
Total federal taxes | 12,600 | 38,500 | 77,300 |
State - | |||
Current | -13,800 | -5,200 | -3,000 |
Deferred | -2,000 | 12,600 | 18,300 |
Total state taxes | -15,800 | 7,400 | 15,300 |
Income taxes | ($3,228) | $45,895 | $92,621 |
Income_Taxes_Deferred_Tax_Asse
Income Taxes - Deferred Tax Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Deferred tax liabilities - | ||
Total - deferred tax liabilities | $11,064,000,000 | $10,420,000,000 |
Deferred Tax Liabilities, Gross | 16,256,000,000 | 13,995,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 5,241,000,000 | 3,624,000,000 |
Total deferred tax liabilities, net | 5,192,000,000 | 3,575,000,000 |
Portion included in current assets/(liabilities), net | 504,000,000 | 143,000,000 |
Valuation allowance | -49,000,000 | -49,000,000 |
Accumulated deferred income taxes | 11,568,000,000 | 10,563,000,000 |
Deferred State Tax Assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 117,000,000 | 77,000,000 |
Asset retirement obligations-asset [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 871,000,000 | 824,000,000 |
Kemper IGCC Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 631,000,000 | 472,000,000 |
Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 67,000,000 | 116,000,000 |
Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 11,125,000,000 | 9,710,000,000 |
Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,332,000,000 | 1,515,000,000 |
Leveraged lease basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 299,000,000 | 287,000,000 |
Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 613,000,000 | 491,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 1,675,000,000 | 1,048,000,000 |
Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,390,000,000 | 705,000,000 |
Premium on reacquired debt [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 103,000,000 | 113,000,000 |
Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 871,000,000 | 824,000,000 |
Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 430,000,000 | 421,000,000 |
Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 523,000,000 | 350,000,000 |
Over recovered fuel clause [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 0 | 30,000,000 |
Other property basis differences [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 453,000,000 | 157,000,000 |
Deferred costs [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 86,000,000 | 84,000,000 |
Tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 480,000,000 | 121,000,000 |
Other Comprehensive Income Losses [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 89,000,000 | 54,000,000 |
Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 342,000,000 | 220,000,000 |
Alabama Power [Member] | ||
Deferred tax liabilities - | ||
Total - deferred tax liabilities | 3,856,000,000 | 3,578,000,000 |
Deferred Tax Liabilities, Gross | 4,997,000,000 | 4,516,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 1,141,000,000 | 938,000,000 |
Portion included in current assets/(liabilities), net | 18,000,000 | 25,000,000 |
Accumulated deferred income taxes | 3,874,000,000 | 3,603,000,000 |
Alabama Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 3,429,000,000 | 3,187,000,000 |
Alabama Power [Member] | Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 457,000,000 | 458,000,000 |
Alabama Power [Member] | Leveraged lease basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 30,000,000 | 33,000,000 |
Alabama Power [Member] | Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 215,000,000 | 209,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 400,000,000 | 231,000,000 |
Alabama Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 366,000,000 | 198,000,000 |
Alabama Power [Member] | Asset retirement obligation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 59,000,000 | 38,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 344,000,000 | 303,000,000 |
Alabama Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 285,000,000 | 265,000,000 |
Alabama Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 219,000,000 | 205,000,000 |
Alabama Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 156,000,000 | 128,000,000 |
Alabama Power [Member] | Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 42,000,000 | 41,000,000 |
Alabama Power [Member] | Storm Reserve [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 27,000,000 | 32,000,000 |
Alabama Power [Member] | Other Comprehensive Income Losses [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 19,000,000 | 18,000,000 |
Alabama Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 90,000,000 | 108,000,000 |
Georgia Power [Member] | ||
Deferred tax liabilities - | ||
Total - deferred tax liabilities | 5,473,000,000 | 5,132,000,000 |
Deferred Tax Liabilities, Gross | 7,210,000,000 | 6,596,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 1,737,000,000 | 1,464,000,000 |
Portion included in current assets/(liabilities), net | 34,000,000 | 68,000,000 |
Accumulated deferred income taxes | 5,507,000,000 | 5,200,000,000 |
Georgia Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 4,732,000,000 | 4,479,000,000 |
Georgia Power [Member] | Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 811,000,000 | 873,000,000 |
Georgia Power [Member] | Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 329,000,000 | 232,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 642,000,000 | 388,000,000 |
Georgia Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 534,000,000 | 276,000,000 |
Georgia Power [Member] | Premium on reacquired debt [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 66,000,000 | 73,000,000 |
Georgia Power [Member] | Under recovered fuel clause [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 81,000,000 | 0 |
Georgia Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 497,000,000 | 495,000,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 497,000,000 | 495,000,000 |
Georgia Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 148,000,000 | 159,000,000 |
Georgia Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 160,000,000 | 168,000,000 |
Georgia Power [Member] | Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 46,000,000 | 53,000,000 |
Georgia Power [Member] | Over recovered fuel clause [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 0 | 22,000,000 |
Georgia Power [Member] | Other property basis differences [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 86,000,000 | 93,000,000 |
Georgia Power [Member] | Deferred costs [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 86,000,000 | 84,000,000 |
Georgia Power [Member] | Cost of removal [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 11,000,000 | 17,000,000 |
Georgia Power [Member] | Tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 170,000,000 | 118,000,000 |
Georgia Power [Member] | Federal Tax Credit Carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 5,000,000 | 3,000,000 |
Georgia Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 46,000,000 | 32,000,000 |
Gulf Power [Member] | ||
Deferred tax liabilities - | ||
Total - deferred tax liabilities | 796,589,000 | 725,974,000 |
Deferred Tax Liabilities, Gross | 968,016,000 | 858,980,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 171,427,000 | 133,006,000 |
Portion included in current assets/(liabilities), net | 3,134,000 | 8,381,000 |
Accumulated deferred income taxes | 799,723,000 | 734,355,000 |
Gulf Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 776,953,000 | 721,087,000 |
Gulf Power [Member] | Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 52,242,000 | 45,960,000 |
Gulf Power [Member] | Employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 34,405,000 | 25,800,000 |
Gulf Power [Member] | Pension and other employee benefits [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 65,506,000 | 33,015,000 |
Gulf Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 59,788,000 | 27,660,000 |
Gulf Power [Member] | Fuel Recovery Clause [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 16,148,000 | 7,972,000 |
Gulf Power [Member] | Asset retirement obligation [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 6,768,000 | 6,554,000 |
Gulf Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 6,768,000 | 6,554,000 |
Gulf Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 30,587,000 | 24,277,000 |
Gulf Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 21,712,000 | 23,947,000 |
Gulf Power [Member] | Other Postretirement Benefits [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 18,033,000 | 17,816,000 |
Gulf Power [Member] | Tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 18,200,000 | 18,420,000 |
Gulf Power [Member] | Property reserve [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 13,440,000 | 15,144,000 |
Gulf Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 18,893,000 | 17,780,000 |
Mississippi Power [Member] | ||
Deferred tax liabilities - | ||
Total - deferred tax liabilities | 146,412,000 | 57,182,000 |
Deferred Tax Liabilities, Gross | 1,397,851,000 | 730,649,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 1,251,439,000 | 673,467,000 |
Portion included in current assets/(liabilities), net | 121,049,000 | 15,626,000 |
Deferred Tax Assets, State Taxes | 17,388,000 | 0 |
Accumulated deferred income taxes | 284,849,000 | 72,808,000 |
Mississippi Power [Member] | Accelerated depreciation [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,068,242,000 | 371,553,000 |
Mississippi Power [Member] | Property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 0 | 130,679,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 263,430,000 | 0 |
Mississippi Power [Member] | Energy Cost Management Clause Over Recovered [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 905,000 | 0 |
Mississippi Power [Member] | NOL State Carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 56,736,000 | 0 |
Mississippi Power [Member] | Energy Cost Management Clause Under Recovered [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 0 | 1,777,000 |
Mississippi Power [Member] | Pension and other employee benefits [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 35,200,000 | 23,769,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 92,232,000 | 57,999,000 |
Mississippi Power [Member] | Regulatory assets associated with employee benefit obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 67,727,000 | 33,127,000 |
Mississippi Power [Member] | Regulatory assets associated with Kemper IGCC [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 61,561,000 | 30,708,000 |
Mississippi Power [Member] | Under recovered fuel clause [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 3,288,000 | 0 |
Mississippi Power [Member] | Asset retirement obligation [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 19,299,000 | 16,764,000 |
Mississippi Power [Member] | Regulatory assets associated with asset retirement obligations [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 19,299,000 | 16,764,000 |
Mississippi Power [Member] | Rate Differential [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 89,040,000 | 56,074,000 |
Mississippi Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,279,000 | 30,615,000 |
Mississippi Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 52,215,000 | 35,583,000 |
Mississippi Power [Member] | Property insurance [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 24,315,000 | 23,693,000 |
Mississippi Power [Member] | Premium on long-term debt [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 20,694,000 | 23,736,000 |
Mississippi Power [Member] | Unbilled revenues [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 14,535,000 | 12,136,000 |
Mississippi Power [Member] | Over recovered fuel clause [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 0 | 7,741,000 |
Mississippi Power [Member] | Kemper IGCC Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 631,326,000 | 472,000,000 |
Mississippi Power [Member] | Interest rate hedges [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 4,544,000 | 5,094,000 |
Mississippi Power [Member] | Kemper Rate Factor - Regulatory Liability Retail [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 108,312,000 | 36,210,000 |
Mississippi Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 15,111,000 | 18,094,000 |
Southern Power [Member] | ||
Deferred tax liabilities - | ||
Total - deferred tax liabilities | 559,200,000 | 724,200,000 |
Deferred Tax Liabilities, Gross | 1,031,900,000 | 844,400,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 480,200,000 | 127,700,000 |
Total deferred tax liabilities, net | 472,700,000 | 120,200,000 |
Portion included in current assets/(liabilities), net | 303,600,000 | 200,000 |
Valuation allowance | -7,500,000 | -7,500,000 |
Accumulated deferred income taxes | 862,795,000 | 724,390,000 |
Southern Power [Member] | Accelerated depreciation and other property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 1,006,500,000 | 829,500,000 |
Southern Power [Member] | Federal effect of state deferred taxes [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 28,900,000 | 29,700,000 |
Southern Power [Member] | Levelized capacity revenues [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 17,100,000 | 11,200,000 |
Deferred tax assets - | ||
Total - deferred tax assets | 4,900,000 | 6,000,000 |
Southern Power [Member] | State Net Operating Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 14,500,000 | 17,000,000 |
Southern Power [Member] | Other deferred tax liabilities [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 5,700,000 | 900,000 |
Southern Power [Member] | Other property basis differences [Member] | ||
Deferred tax liabilities - | ||
Deferred Tax Liabilities, Gross | 2,600,000 | 2,800,000 |
Southern Power [Member] | Tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 15,000,000 | 1,100,000 |
Southern Power [Member] | Unrealized Tax Credits [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 305,200,000 | 0 |
Southern Power [Member] | Investment tax credit carryforward [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 101,500,000 | 58,000,000 |
Southern Power [Member] | Unrealized Loss [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | 6,100,000 | 11,200,000 |
Southern Power [Member] | Other deferred tax assets [Member] | ||
Deferred tax assets - | ||
Total - deferred tax assets | $4,100,000 | $4,700,000 |
Income_Taxes_Reconciliation_of
Income Taxes - Reconciliation of Federal Statutory Income Tax Rate (Details) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | 2.30% | 2.50% | 2.50% |
Employee stock plans dividend deduction | -1.40% | -1.60% | -1.00% |
Non-deductible book depreciation | 1.40% | 1.50% | 0.90% |
AFUDC-Equity | -2.90% | -2.60% | -1.30% |
ITC basis difference | -1.60% | -1.20% | -0.30% |
Other | -0.30% | -0.50% | -0.20% |
Effective income tax rate | 32.50% | 33.10% | 35.60% |
Alabama Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | 4.40% | 4.00% | 4.10% |
Non-deductible book depreciation | 1.10% | 1.00% | 0.90% |
Difference in prior years' deferred and current tax rate | -0.10% | -0.10% | -0.10% |
AFUDC-Equity | -1.30% | -0.90% | -0.50% |
Other | -0.10% | -0.10% | -0.30% |
Effective income tax rate | 39.00% | 38.90% | 39.10% |
Georgia Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | 2.20% | 2.50% | 1.60% |
Non-deductible book depreciation | 1.30% | 1.30% | 1.20% |
AFUDC-Equity | -0.80% | -0.60% | -1.00% |
Other | -0.70% | -0.40% | -0.10% |
Effective income tax rate | 37.00% | 37.80% | 36.70% |
Gulf Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | 3.50% | 3.50% | 3.30% |
Non-deductible book depreciation | 0.40% | 0.50% | 0.50% |
Difference in prior years' deferred and current tax rate | -0.10% | -0.20% | -0.20% |
AFUDC-Equity | -1.80% | -1.10% | -0.90% |
Other | 0.10% | -0.10% | -0.20% |
Effective income tax rate | 37.10% | 37.60% | 37.50% |
Mississippi Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | -35.00% | -35.00% | 35.00% |
State income tax, net of federal deduction | -4.00% | -3.70% | 1.30% |
Non-deductible book depreciation | 0.10% | 0.10% | 0.30% |
AFUDC-Equity | -7.80% | -5.00% | -18.60% |
Other | 0.10% | -0.10% | -1.20% |
Effective income tax rate | -46.60% | -43.70% | 16.80% |
Southern Power [Member] | |||
Reconciliation of federal statutory income tax rate to effective income tax rate | |||
Federal statutory rate | 35.00% | 35.00% | 35.00% |
State income tax, net of federal deduction | -6.00% | 2.20% | 3.70% |
Amortization of ITC | -4.30% | -1.70% | -1.00% |
ITC basis difference | -27.70% | -14.50% | -2.60% |
Other | 1.10% | 0.30% | -0.60% |
Effective income tax rate | -1.90% | 21.30% | 34.50% |
Income_Taxes_Changes_in_Unreco
Income Taxes - Changes in Unrecognized Tax Benefits (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | $7,000,000 | $70,000,000 | $120,000,000 |
Tax positions from current periods | 64,000,000 | 3,000,000 | 13,000,000 |
Tax positions increase from prior periods | 102,000,000 | 0 | 7,000,000 |
Tax positions decrease from prior periods | -3,000,000 | -66,000,000 | -56,000,000 |
Reductions due to settlements | 0 | 0 | -10,000,000 |
Reductions due to expired statute of limitations | 0 | 0 | -4,000,000 |
Unrecognized tax benefits at end of year | 170,000,000 | 7,000,000 | 70,000,000 |
Alabama Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 31,000,000 | 32,000,000 | |
Tax positions from current periods | 0 | 5,000,000 | |
Tax positions decrease from prior periods | -31,000,000 | -4,000,000 | |
Reductions due to settlements | 0 | -2,000,000 | |
Unrecognized tax benefits at end of year | 0 | 31,000,000 | |
Georgia Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 23,000,000 | 47,000,000 | |
Tax positions from current periods | 0 | 3,000,000 | |
Tax positions increase from prior periods | 0 | 3,000,000 | |
Tax positions decrease from prior periods | -23,000,000 | -19,000,000 | |
Reductions due to settlements | 0 | -8,000,000 | |
Reductions due to expired statute of limitations | 0 | -3,000,000 | |
Unrecognized tax benefits at end of year | 0 | 23,000,000 | |
Gulf Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 45,000 | 5,007,000 | 2,892,000 |
Tax positions from current periods | 46,000 | 45,000 | 2,630,000 |
Tax positions increase from prior periods | 515,000 | ||
Tax positions decrease from prior periods | -45,000 | -5,007,000 | |
Reductions due to settlements | 0 | 0 | -1,030,000 |
Unrecognized tax benefits at end of year | 46,000 | 45,000 | 5,007,000 |
Mississippi Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 3,840,000 | 5,755,000 | 4,964,000 |
Tax positions from current periods | 58,148,000 | 226,000 | 1,186,000 |
Tax positions increase from prior periods | 102,833,000 | ||
Tax positions decrease from prior periods | -2,141,000 | -26,000 | |
Reductions due to settlements | 0 | 0 | -369,000 |
Unrecognized tax benefits at end of year | 164,821,000 | 3,840,000 | 5,755,000 |
Southern Power [Member] | |||
Changes in unrecognized tax benefits [Roll Forward] | |||
Unrecognized tax benefits at beginning of year | 1,500,000 | 2,900,000 | 2,600,000 |
Tax positions from current periods | 4,700,000 | 1,600,000 | 700,000 |
Tax positions decrease from prior periods | -1,500,000 | -3,000,000 | -200,000 |
Reductions due to settlements | 0 | 0 | -200,000 |
Unrecognized tax benefits at end of year | $4,700,000 | $1,500,000 | $2,900,000 |
Income_Taxes_Impact_of_Unrecog
Income Taxes - Impact of Unrecognized Tax Benefits on Effective Tax Rate, If Recognized (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
In Thousands, unless otherwise specified | ||||
Impact on effective tax rate | ||||
Tax positions impacting the effective tax rate | $10,000 | $7,000 | $5,000 | |
Tax positions not impacting the effective tax rate | 160,000 | 0 | 65,000 | |
Balance of unrecognized tax benefits | 170,000 | 7,000 | 70,000 | 120,000 |
Alabama Power [Member] | ||||
Impact on effective tax rate | ||||
Balance of unrecognized tax benefits | 0 | 31,000 | 32,000 | |
Georgia Power [Member] | ||||
Impact on effective tax rate | ||||
Balance of unrecognized tax benefits | 0 | 23,000 | 47,000 | |
Gulf Power [Member] | ||||
Impact on effective tax rate | ||||
Tax positions impacting the effective tax rate | 46 | 45 | 45 | |
Tax positions not impacting the effective tax rate | 0 | 0 | 4,962 | |
Balance of unrecognized tax benefits | 46 | 45 | 5,007 | 2,892 |
Mississippi Power [Member] | ||||
Impact on effective tax rate | ||||
Tax positions impacting the effective tax rate | 4,341 | 3,840 | 3,656 | |
Tax positions not impacting the effective tax rate | 160,480 | 0 | 2,099 | |
Balance of unrecognized tax benefits | 164,821 | 3,840 | 5,755 | 4,964 |
Southern Power [Member] | ||||
Impact on effective tax rate | ||||
Tax positions impacting the effective tax rate | 4,700 | 1,500 | 300 | |
Tax positions not impacting the effective tax rate | 0 | 0 | 2,600 | |
Balance of unrecognized tax benefits | $4,700 | $1,500 | $2,900 | $2,600 |
Income_Taxes_Accrued_Interest_
Income Taxes - Accrued Interest for Unrecognized Tax Benefits (Details) (Mississippi Power [Member], USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Mississippi Power [Member] | |||
Reconciliation of Accrued Interest For Unrecognized Tax Benefits [Roll Forward] | |||
Interest accrued at beginning of year | $1,171 | $772 | $680 |
Interest accrued during the period | 1,698 | 399 | 92 |
Balance at end of year | $2,869 | $1,171 | $772 |
Income_Taxes_Textual_Details
Income Taxes - Textual (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Income Tax Disclosure [Line Items] | ||||
Net cash payments/(refunds) for income taxes | $272,000,000 | $139,000,000 | $38,000,000 | |
Net operating loss carryforward | 701,000,000 | |||
State income tax benefits as a result of utilization of State of Georgia net operating loss carryforward | 41,000,000 | |||
Deferred tax assets | 5,241,000,000 | 3,624,000,000 | ||
Tax Credit Carryforward, Amount | 379,000,000 | |||
State Investment Tax Credit | 159,000,000 | |||
Tax regulatory assets | 1,500,000,000 | |||
Tax regulatory liabilities | 192,000,000 | |||
Amortization of deferred investment tax credits | 22,000,000 | 16,000,000 | 23,000,000 | |
Unamortized investment tax credits | 1,208,000,000 | 966,000,000 | ||
Unrecognized Tax Benefits | 170,000,000 | 7,000,000 | 70,000,000 | 120,000,000 |
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | |||
Kemper IGCC [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Unrecognized Tax Benefits | 160,000,000 | |||
Alabama Power [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Net cash payments/(refunds) for income taxes | 436,000,000 | 296,000,000 | 309,000,000 | |
Deferred tax assets | 1,141,000,000 | 938,000,000 | ||
Tax regulatory assets | 526,000,000 | |||
Tax regulatory liabilities | 72,000,000 | |||
Amortization of deferred investment tax credits | 8,000,000 | 8,000,000 | 8,000,000 | |
Unamortized investment tax credits | 125,000,000 | 133,000,000 | ||
Unrecognized Tax Benefits | 0 | 31,000,000 | 32,000,000 | |
Georgia Power [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Net cash payments/(refunds) for income taxes | 507,000,000 | 298,000,000 | 312,000,000 | |
Deferred tax assets | 1,737,000,000 | 1,464,000,000 | ||
State Investment Tax Credit | 34,000,000 | 27,000,000 | 36,000,000 | |
Tax regulatory assets | 702,000,000 | |||
Tax regulatory liabilities | 106,000,000 | |||
Regulatory Liabilities | 62,000,000 | |||
Amortization of deferred investment tax credits | 10,000,000 | 5,000,000 | 13,000,000 | |
Federal Tax Credits | 5,000,000 | |||
State Investment Tax Credit Carryforward | 152,000,000 | |||
Unamortized investment tax credits | 196,000,000 | 203,000,000 | ||
Unrecognized Tax Benefits | 0 | 23,000,000 | 47,000,000 | |
Gulf Power [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Net cash payments/(refunds) for income taxes | 44,125,000 | -10,727,000 | -96,639,000 | |
Deferred tax assets | 171,427,000 | 133,006,000 | ||
Tax regulatory assets | 56,300,000 | |||
Tax regulatory liabilities | 3,900,000 | |||
Amortization of deferred investment tax credits | 1,300,000 | 1,400,000 | 1,400,000 | |
Unamortized investment tax credits | 2,783,000 | 4,055,000 | ||
Unrecognized Tax Benefits | 46,000 | 45,000 | 5,007,000 | 2,892,000 |
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | |||
Mississippi Power [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Net cash payments/(refunds) for income taxes | -379,158,000 | -134,198,000 | -77,580,000 | |
Deferred tax assets | 1,251,439,000 | 673,467,000 | ||
Tax Credit Carryforward, Amount | 276,400,000 | |||
Tax regulatory assets | 226,200,000 | |||
Tax regulatory liabilities | 9,400,000 | |||
Amortization of deferred investment tax credits | 1,400,000 | 1,200,000 | 1,200,000 | |
Unamortized investment tax credits | 282,816,000 | 284,248,000 | ||
Minimum Percentage of Carbon Dioxide That Must Capture and Sequester to Remain Eligible for Tax Credits | 65.00% | |||
Unrecognized Tax Benefits | 164,821,000 | 3,840,000 | 5,755,000 | 4,964,000 |
Mississippi Power [Member] | Kemper IGCC [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Unamortized investment tax credits | 276,400,000 | |||
Southern Power [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Net cash payments/(refunds) for income taxes | -219,641,000 | -226,179,000 | -175,269,000 | |
Net operating loss carryforward | 246,600,000 | 240,800,000 | ||
Deferred tax assets | 480,200,000 | 127,700,000 | ||
Increase (decrease) in deferred tax assets valuation allowance | 15,100,000 | |||
Operating Loss Carryforwards In Year Three | 87,000,000 | |||
Operating Loss Carryforwards In Year Four | 40,000,000 | |||
Amortization of deferred investment tax credits | 11,399,000 | 5,535,000 | 2,633,000 | |
Unrecognized Tax Benefits | 4,700,000 | 1,500,000 | 2,900,000 | 2,600,000 |
Significantly increase or decrease in the amount of the unrecognized tax benefits associated with a majority of Southern | 12 months | |||
Southern Power [Member] | Operating Loss Carryforward [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Deferred tax assets | 9,400,000 | 11,000,000 | ||
Southern Power [Member] | Investment tax credit carryforward [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Deferred tax assets | 101,500,000 | 58,000,000 | ||
Southern Power [Member] | Investment tax credit carryforward [Member] | Nacogdoches Biomass Generating Plant [Member] | ||||
Income Tax Disclosure [Line Items] | ||||
Tax credit carryforward | 73,500,000 | 158,100,000 | 45,000,000 | |
Reduction in income tax expense, investment tax credits | ($47,500,000) | ($31,300,000) | ($7,800,000) |
Financing_Scheduled_Maturities
Financing - Scheduled Maturities and Redemptions of Securities Due Within One Year (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | ||
Scheduled maturities and redemptions of securities due within one year | |||
Senior notes | $2,375,000,000 | $428,000,000 | |
Other long-term debt | 775,000,000 | 12,000,000 | |
Capitalized leases | 31,000,000 | 29,000,000 | |
Pollution control revenue bonds | 152,000,000 | 0 | |
Total | 3,333,000,000 | 469,000,000 | |
Alabama Power [Member] | |||
Scheduled maturities and redemptions of securities due within one year | |||
Total | 454,000,000 | 0 | |
Alabama Power [Member] | 4.92% Redeemable Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0492 | ||
Par Value/Stated Capital Per Share | $100 | [1] | |
Temporary Equity, Shares Outstanding | 80,000 | [1] | |
Redemption Price Per Share | $103.23 | [1] | |
Alabama Power [Member] | 4.72% Redeemable Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0472 | ||
Par Value/Stated Capital Per Share | $100 | [1] | |
Temporary Equity, Shares Outstanding | 50,000 | [1] | |
Redemption Price Per Share | $102.18 | [1] | |
Alabama Power [Member] | 4.64% Redeemable Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0464 | ||
Par Value/Stated Capital Per Share | $100 | [1] | |
Temporary Equity, Shares Outstanding | 60,000 | [1] | |
Redemption Price Per Share | $103.14 | [1] | |
Alabama Power [Member] | 4.60% Redeemable Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.046 | ||
Par Value/Stated Capital Per Share | $100 | [1] | |
Temporary Equity, Shares Outstanding | 100,000 | [1] | |
Redemption Price Per Share | $104.20 | [1] | |
Alabama Power [Member] | 4.52% Redeemable Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0452 | ||
Par Value/Stated Capital Per Share | $100 | [1] | |
Temporary Equity, Shares Outstanding | 50,000 | [1] | |
Redemption Price Per Share | $102.93 | [1] | |
Alabama Power [Member] | 4.20% Redeemable Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.042 | ||
Par Value/Stated Capital Per Share | $100 | [1] | |
Temporary Equity, Shares Outstanding | 135,115 | [1] | |
Redemption Price Per Share | $105 | [1] | |
Alabama Power [Member] | 5.83% Class A Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0583 | ||
Par Value/Stated Capital Per Share | $25 | ||
Temporary Equity, Shares Outstanding | 1,520,000 | ||
Alabama Power [Member] | 5.20% Class A Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.052 | ||
Par Value/Stated Capital Per Share | $25 | ||
Temporary Equity, Shares Outstanding | 6,480,000 | ||
Alabama Power [Member] | 5.30% Class A Preferred Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.053 | ||
Par Value/Stated Capital Per Share | $25 | ||
Temporary Equity, Shares Outstanding | 4,000,000 | ||
Alabama Power [Member] | 5.625% Preference Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.05625 | ||
Par Value/Stated Capital Per Share | $25 | ||
Temporary Equity, Shares Outstanding | 6,000,000 | ||
Alabama Power [Member] | 6.450% Preference Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.0645 | ||
Par Value/Stated Capital Per Share | $25 | [1] | |
Temporary Equity, Shares Outstanding | 6,000,000 | [1] | |
Alabama Power [Member] | 6.500% Preference Stock [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Redeemable Preferred Stock/Preference Stock dividend rate percentage | 0.065 | ||
Par Value/Stated Capital Per Share | $25 | [1] | |
Temporary Equity, Shares Outstanding | 2,000,000 | [1] | |
Georgia Power [Member] | |||
Scheduled maturities and redemptions of securities due within one year | |||
Senior notes | 1,050,000,000 | 0 | |
Capitalized leases | 6,000,000 | 5,000,000 | |
Pollution control revenue bonds | 98,000,000 | 0 | |
Total | 1,154,000,000 | 5,000,000 | |
Mississippi Power [Member] | |||
Redeemable Preferred/Preference Stock [Abstract] | |||
Temporary Equity, Shares Outstanding | 334,210 | 334,210 | |
Scheduled maturities and redemptions of securities due within one year | |||
Capitalized leases | 2,700,000 | 2,500,000 | |
Pollution control revenue bonds | 0 | 11,300,000 | |
Bank term loans | 775,000,000 | 0 | |
Total | $777,667,000 | $13,789,000 | |
[1] | Prior to 10/01/2017: Stated Value Plus Make-Whole Premium; after 10/01/2017: Stated Capital |
Financing_Committed_Credit_Arr
Financing - Committed Credit Arrangements With Banks (Details) (USD $) | Dec. 31, 2014 | |
In Millions, unless otherwise specified | ||
Credit arrangements by company | ||
Expires, 2015 | $513 | |
Expires, 2016 | 530 | |
Expires, 2017 | 30 | |
Expires, 2018 | 4,130 | |
Total | 5,203 | |
Unused | 5,177 | |
Executable Term-Loans, One Year | 153 | |
Executable Term-Loans, Two Years | 40 | |
Due Within One Year, Term Out | 193 | |
Due Within One Year, No Term Out | 320 | |
Southern Company [Member] | ||
Credit arrangements by company | ||
Expires, 2015 | 0 | |
Expires, 2016 | 0 | |
Expires, 2017 | 0 | |
Expires, 2018 | 1,000 | |
Total | 1,000 | |
Unused | 1,000 | |
Executable Term-Loans, One Year | 0 | |
Executable Term-Loans, Two Years | 0 | |
Due Within One Year, Term Out | 0 | |
Due Within One Year, No Term Out | 0 | |
Alabama Power [Member] | ||
Credit arrangements by company | ||
Expires, 2015 | 228 | [1] |
Expires, 2016 | 50 | [1] |
Expires, 2017 | 0 | |
Expires, 2018 | 1,030 | [1] |
Total | 1,308 | |
Unused | 1,308 | |
Executable Term-Loans, One Year | 58 | |
Executable Term-Loans, Two Years | 0 | |
Due Within One Year, Term Out | 58 | |
Due Within One Year, No Term Out | 170 | |
Georgia Power [Member] | ||
Credit arrangements by company | ||
Expires, 2015 | 0 | |
Expires, 2016 | 150 | [2] |
Expires, 2017 | 0 | |
Expires, 2018 | 1,600 | [2] |
Total | 1,750 | |
Unused | 1,736 | |
Executable Term-Loans, One Year | 0 | |
Executable Term-Loans, Two Years | 0 | |
Due Within One Year, Term Out | 0 | |
Due Within One Year, No Term Out | 0 | |
Gulf Power [Member] | ||
Credit arrangements by company | ||
Expires, 2015 | 80 | [3] |
Expires, 2016 | 165 | [3] |
Expires, 2017 | 30 | [3] |
Expires, 2018 | 0 | |
Total | 275 | |
Unused | 275 | |
Executable Term-Loans, One Year | 50 | |
Executable Term-Loans, Two Years | 0 | |
Due Within One Year, Term Out | 50 | |
Due Within One Year, No Term Out | 30 | |
Mississippi Power [Member] | ||
Credit arrangements by company | ||
Expires, 2015 | 135 | |
Expires, 2016 | 165 | |
Expires, 2017 | 0 | |
Expires, 2018 | 0 | |
Total | 300 | |
Unused | 300 | |
Executable Term-Loans, One Year | 25 | |
Executable Term-Loans, Two Years | 40 | |
Due Within One Year, Term Out | 65 | |
Due Within One Year, No Term Out | 70 | |
Southern Power [Member] | ||
Credit arrangements by company | ||
Expires, 2015 | 0 | |
Expires, 2016 | 0 | |
Expires, 2017 | 0 | |
Expires, 2018 | 500 | |
Total | 500 | |
Unused | 488 | |
Executable Term-Loans, One Year | 0 | |
Executable Term-Loans, Two Years | 0 | |
Due Within One Year, Term Out | 0 | |
Due Within One Year, No Term Out | 0 | |
Other Subsidiaries [Member] | ||
Credit arrangements by company | ||
Expires, 2015 | 70 | |
Expires, 2016 | 0 | |
Expires, 2017 | 0 | |
Expires, 2018 | 0 | |
Total | 70 | |
Unused | 70 | |
Executable Term-Loans, One Year | 20 | |
Executable Term-Loans, Two Years | 0 | |
Due Within One Year, Term Out | 20 | |
Due Within One Year, No Term Out | $50 | |
[1] | No credit arrangements expire in 2017. | |
[2] | No credit arrangements expire in 2015 or 2017 | |
[3] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjQ1MzFhOWM1ZmVjMjQ1Zjk4ODFkOGZjMmQyYjdiOWRhfFRleHRTZWxlY3Rpb246Mjc3MUE3QkUxQkE0QjU1ODM2REUwQkE4RkE0RjNEOEIM} |
Financing_Shortterm_Borrowings
Financing - Short-term Borrowings (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
Short-term Debt [Line Items] | ||||
Expires, 2017 | $30,000,000 | |||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 803,000,000 | [1] | 1,482,000,000 | [1] |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.30% | [1] | 0.40% | [1] |
Commercial paper [Member] | ||||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 803,000,000 | [1] | 1,082,000,000 | [1] |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.30% | [1] | 0.20% | [1] |
Short-term bank debt [Member] | ||||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 0 | [1] | 400,000,000 | [1] |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.00% | [1] | 0.90% | [1] |
Parent Company [Member] | ||||
Short-term Debt [Line Items] | ||||
Expires, 2017 | 0 | |||
Georgia Power [Member] | ||||
Short-term Debt [Line Items] | ||||
Expires, 2017 | 0 | |||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 1,047,000,000 | |||
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.50% | |||
Georgia Power [Member] | Commercial paper [Member] | ||||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 156,000,000 | 647,000,000 | ||
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.30% | 0.20% | ||
Georgia Power [Member] | Short-term bank debt [Member] | ||||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 400,000,000 | |||
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.90% | |||
Alabama Power [Member] | ||||
Short-term Debt [Line Items] | ||||
Expires, 2017 | 0 | |||
Gulf Power [Member] | ||||
Short-term Debt [Line Items] | ||||
Expires, 2017 | 30,000,000 | [2] | ||
Gulf Power [Member] | Commercial paper [Member] | ||||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 110,000,000 | [3] | 136,000,000 | [3] |
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.30% | [3] | 0.20% | [3] |
Mississippi Power [Member] | ||||
Short-term Debt [Line Items] | ||||
Expires, 2017 | 0 | |||
Short-term borrowings | ||||
Taxable Revenue Bonds | 11,300,000 | |||
Southern Power [Member] | ||||
Short-term Debt [Line Items] | ||||
Expires, 2017 | 0 | |||
Southern Power [Member] | Commercial paper [Member] | ||||
Short-term borrowings | ||||
Short-term Debt at the End of the Period, Amount Outstanding | 195,000,000 | |||
Short-term Debt at the End of the Period, Weighted Average Interest Rate | 0.40% | |||
Other Subsidiaries [Member] | ||||
Short-term Debt [Line Items] | ||||
Expires, 2017 | $0 | |||
[1] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjQ1MzFhOWM1ZmVjMjQ1Zjk4ODFkOGZjMmQyYjdiOWRhfFRleHRTZWxlY3Rpb246OERGRTI3MTUxN0I0NzI4MTdBQTIwQkE4RkEzRjI3MjgM} | |||
[2] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjQ1MzFhOWM1ZmVjMjQ1Zjk4ODFkOGZjMmQyYjdiOWRhfFRleHRTZWxlY3Rpb246Mjc3MUE3QkUxQkE0QjU1ODM2REUwQkE4RkE0RjNEOEIM} | |||
[3] | Commercial PaperB atB theEnd of the Period Amount OutstandingB WeightedAverageInterestRateB (in millions) DecemberB 31, 2014$110B 0.3%DecemberB 31, 2013$136B 0.2% |
Financing_Textual_Details
Financing - Textual (Details) (USD $) | 1 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 12 Months Ended | |||||||||||||||||
Jun. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 20, 2014 | Feb. 28, 2014 | Jan. 31, 2014 | Jan. 31, 2015 | 31-May-14 | Sep. 30, 2013 | Dec. 31, 2011 | Dec. 11, 2014 | Jul. 31, 2014 | Apr. 30, 2014 | Sep. 30, 2014 | Feb. 28, 2013 | Oct. 31, 2014 | Oct. 09, 2014 | Jan. 04, 2014 | Mar. 31, 2012 | Aug. 31, 2014 | Nov. 30, 2013 | |
loan | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Proceeds from issuance of junior subordinated notes | $206,000,000 | $206,000,000 | ||||||||||||||||||||
Other Long-term Debt | 4,719,000,000 | 3,503,000,000 | ||||||||||||||||||||
Senior notes, current | 2,375,000,000 | 428,000,000 | ||||||||||||||||||||
Other Long-term Debt | 775,000,000 | 12,000,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2014 | 3,330,000,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2015 | 1,830,000,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2016 | 1,550,000,000 | |||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four | 862,000,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 1,210,000,000 | |||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 2,375,000,000 | 2,375,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 1,360,000,000 | 1,360,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 1,495,000,000 | 1,095,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 1,175,000,000 | 825,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 850,000,000 | 850,000,000 | ||||||||||||||||||||
Description of variable rate basis | one-month | one-month | ||||||||||||||||||||
Bank loans, period of extension | 90 days | |||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | 250,000,000 | |||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | |||||||||||||||||||||
Senior Notes outstanding | 18,200,000,000 | 17,300,000,000 | ||||||||||||||||||||
Derivative, Notional Amount | 2,050,000,000 | |||||||||||||||||||||
Capitalized lease obligations | 159,000,000 | 163,000,000 | ||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 24,059,000,000 | 23,059,000,000 | ||||||||||||||||||||
Unused credit with banks | 5,177,000,000 | |||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | 1,800,000,000 | |||||||||||||||||||||
Remarketed pollution control bonds | 476,000,000 | |||||||||||||||||||||
Long-term Pollution Control Bond, Current | 152,000,000 | 0 | ||||||||||||||||||||
Common Stock, Shares, Issued | 909,000,000 | 893,000,000 | ||||||||||||||||||||
Proceeds from Issuance of Common Stock | 806,000,000 | 695,000,000 | 397,000,000 | |||||||||||||||||||
Short-term Debt | 803,000,000 | 1,482,000,000 | ||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Trust Preferred Securities Subject to Mandatory Redemption [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Preferred securities, outstanding | 200,000,000 | 200,000,000 | ||||||||||||||||||||
Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 750,000,000 | |||||||||||||||||||||
Georgia Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Other Long-term Debt | 2,883,000,000 | 1,680,000,000 | ||||||||||||||||||||
Senior notes, current | 1,050,000,000 | 0 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2014 | 1,200,000,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2015 | 710,000,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2016 | 457,000,000 | |||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four | 257,000,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 508,000,000 | |||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 1,050,000,000 | 1,050,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 250,000,000 | 250,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 450,000,000 | 450,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 500,000,000 | 500,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 250,000,000 | 250,000,000 | ||||||||||||||||||||
Repayments of Pollution Control Bond | 37,000,000 | 298,000,000 | 284,000,000 | |||||||||||||||||||
Bank Loans | 400,000,000 | |||||||||||||||||||||
Bank loans, period of extension | 4 months | |||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | 400,000,000 | |||||||||||||||||||||
Number Of Bank Loans | 3 | |||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | |||||||||||||||||||||
Percent Of Eligible Project Costs To Be Reimbursed | 70.00% | |||||||||||||||||||||
Eligible Project Costs To Be Reimbursed | 3,460,000,000 | |||||||||||||||||||||
Debt Instrument, Basis Spread on Variable Rate | 0.38% | |||||||||||||||||||||
Payments of Debt Issuance Costs | 66,000,000 | |||||||||||||||||||||
Senior Notes outstanding | 6,900,000,000 | |||||||||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 1,000,000,000 | 200,000,000 | ||||||||||||||||||||
Amortization Period For Line Of Credit Facility | 5 years | |||||||||||||||||||||
Pollution control revenue bonds, outstanding | 1,600,000,000 | 1,700,000,000 | ||||||||||||||||||||
Derivative, Notional Amount | 1,600,000,000 | |||||||||||||||||||||
Capitalized lease obligations | 40,000,000 | 45,000,000 | ||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 11,222,000,000 | 10,970,000,000 | ||||||||||||||||||||
Unused credit with banks | 1,736,000,000 | |||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | 865,000,000 | |||||||||||||||||||||
Pollution Control Revenue Bonds Required To Be Remarketed | 118,000,000 | |||||||||||||||||||||
Long-term Pollution Control Bond, Current | 98,000,000 | 0 | ||||||||||||||||||||
Redemption price of redeemable preferred stock, as a percent of liquidation amount | 100.00% | |||||||||||||||||||||
Short-term Debt | 156,000,000 | 1,047,000,000 | ||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Georgia Power [Member] | Corporate, Non-Segment [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | 61,000,000 | 61,000,000 | ||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 21,000,000 | 16,000,000 | ||||||||||||||||||||
Georgia Power [Member] | FIrst Series 2009 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Repayment Aggregate Principal Amount Of Floating Rate Bank Loan | 40,000,000 | |||||||||||||||||||||
Georgia Power [Member] | Redemption In Connection With Unit Retirement [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Long-term Pollution Control Bond, Current | 98,000,000 | |||||||||||||||||||||
Georgia Power [Member] | Line of Credit [Member] | Debt Due 2029 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 500,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.49% | |||||||||||||||||||||
Georgia Power [Member] | Line of Credit [Member] | Debt Due Two Thousand Forty Four [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 500,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.86% | 3.00% | ||||||||||||||||||||
Georgia Power [Member] | Capital Lease Obligations [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.90% | 7.90% | ||||||||||||||||||||
Georgia Power [Member] | Secured Debt [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Long-term Debt | 1,200,000,000 | 45,000,000 | ||||||||||||||||||||
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 45.70% | |||||||||||||||||||||
Georgia Power [Member] | Vogtle Units Three and Four [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 45.70% | |||||||||||||||||||||
Subsidiaries [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | 34,000,000 | 30,000,000 | ||||||||||||||||||||
Subsidiaries [Member] | Capital Lease Obligations [Member] | Minimum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 1.40% | |||||||||||||||||||||
Subsidiaries [Member] | Capital Lease Obligations [Member] | Maximum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 3.20% | |||||||||||||||||||||
Southern Power and Traditional Operating Companies [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 600,000,000 | |||||||||||||||||||||
Gulf Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Other Long-term Debt | 308,955,000 | 295,955,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 0 | 75,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 110,000,000 | 110,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 85,000,000 | 85,000,000 | ||||||||||||||||||||
Repayments of Pollution Control Bond | 29,075,000 | 76,000,000 | 13,000,000 | |||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | |||||||||||||||||||||
Line of Credit Facility, Amount Available to Support Variable Rate Pollution Control Revenue Bonds | 69,000,000 | |||||||||||||||||||||
Senior Notes outstanding | 1,070,000,000 | 945,000,000 | ||||||||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 275,000,000 | |||||||||||||||||||||
Secured Debt | 41,000,000 | |||||||||||||||||||||
Pollution control revenue bonds, outstanding | 309,000,000 | 296,000,000 | ||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,295,714,000 | 1,211,336,000 | ||||||||||||||||||||
Unused credit with banks | 275,000,000 | |||||||||||||||||||||
Pollution Control Revenue Bonds Required To Be Remarketed | 78,000,000 | |||||||||||||||||||||
Redemption price of redeemable preferred stock, as a percent of liquidation amount | 100.00% | |||||||||||||||||||||
Common Stock, Shares, Issued | 500,000 | |||||||||||||||||||||
Proceeds from Issuance of Common Stock | 50,000,000 | 40,000,000 | 40,000,000 | 50,000,000 | ||||||||||||||||||
Number of Issuance Pollution Control Revenue Bonds | 2 | |||||||||||||||||||||
Short-term Debt | 109,977,000 | 135,878,000 | ||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Gulf Power [Member] | Subsequent Event [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Common Stock, Shares, Issued | 200,000 | |||||||||||||||||||||
Proceeds from Issuance of Common Stock | 20,000,000 | |||||||||||||||||||||
Gulf Power [Member] | Minimum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redeemable preferred stock, redemption period | 5 years | |||||||||||||||||||||
Gulf Power [Member] | Maximum [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redeemable preferred stock, redemption period | 10 years | |||||||||||||||||||||
Gulf Power [Member] | Plant Daniel [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 41,000,000 | |||||||||||||||||||||
Gulf Power [Member] | Series Two Thousand Twelve [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 13,000,000 | |||||||||||||||||||||
Gulf Power [Member] | First Series Two Thousand Fourteen [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 29,075,000 | |||||||||||||||||||||
Gulf Power [Member] | Series Two Thousand Three [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redemption Amount of Principal | 29,075,000 | |||||||||||||||||||||
Gulf Power [Member] | Series Two Thousand Fourteen A [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 200,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.55% | |||||||||||||||||||||
Gulf Power [Member] | Series K [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redemption Amount of Principal Notes | 75,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.90% | |||||||||||||||||||||
Southern Company [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Senior Notes outstanding | 2,200,000,000 | 1,800,000,000 | ||||||||||||||||||||
Unused credit with banks | 1,000,000,000 | |||||||||||||||||||||
Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Prepayment of debt | 9,500,000 | |||||||||||||||||||||
Other Long-term Debt | 18,800,000 | 17,800,000 | ||||||||||||||||||||
Senior notes, current | 525,000,000 | |||||||||||||||||||||
Other Long-term Debt | 300,000 | 600,000 | ||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | |||||||||||||||||||||
Line of Credit Facility, Amount Outstanding | 0 | |||||||||||||||||||||
Senior Notes outstanding | 1,600,000,000 | |||||||||||||||||||||
Line of Credit Facility, Current Borrowing Capacity | 500,000,000 | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,034,610,000 | 871,963,000 | ||||||||||||||||||||
Unused credit with banks | 488,000,000 | |||||||||||||||||||||
Short-term Debt | 194,917,000 | 0 | ||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Projected cash flows from fixed price PPAs, as a percentage of total projected cash flows for the next 12 months | 80.00% | |||||||||||||||||||||
Ratio of indebtedness to capitalization, actual, end of period | 60.00% | |||||||||||||||||||||
Southern Power [Member] | Series 2013A [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 300,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.25% | |||||||||||||||||||||
Mississippi Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Promissory Note | 220,000,000 | |||||||||||||||||||||
Other Long-term Debt | 352,695,000 | 352,695,000 | ||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2014 | 777,700,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2015 | 302,800,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2016 | 37,900,000 | |||||||||||||||||||||
Long Term Debt and Capital Lease Obligation Maturities Repayments in Year Four | 3,100,000 | |||||||||||||||||||||
Long term debt and capital lease obligations, maturities in 2018 | 128,200,000 | |||||||||||||||||||||
Long-term debt maturities, 2016 | 300,000,000 | 300,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 35,000,000 | 35,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 125,000,000 | 125,000,000 | ||||||||||||||||||||
Description of variable rate basis | one-month | one-month | ||||||||||||||||||||
Bank Loans | 775,000,000 | 525,000,000 | ||||||||||||||||||||
Bank loans, period of extension | 18 months | 19 months | ||||||||||||||||||||
Aggregate Principal Amount Of Floating Rate Bank Loan | 250,000,000 | |||||||||||||||||||||
Bank loans outstanding | 775,000,000 | 525,000,000 | ||||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | |||||||||||||||||||||
Senior Notes outstanding | 1,100,000,000 | 1,100,000,000 | ||||||||||||||||||||
Pollution control revenue bonds, outstanding | 82,700,000 | 82,700,000 | ||||||||||||||||||||
Revenue bond obligations face value | 270,000,000 | |||||||||||||||||||||
Fixed stated interest rate of debt obligation | 10.13% | 9.93% | 9.97% | 7.13% | ||||||||||||||||||
Other revenue bond obligation | 50,000,000 | 50,000,000 | ||||||||||||||||||||
Taxable Revenue Bonds | 11,300,000 | |||||||||||||||||||||
Period Of Nitrogen Supply Agreement | 20 years | |||||||||||||||||||||
Capitalized lease obligations | 79,679,000 | 82,217,000 | ||||||||||||||||||||
Capital leases, due 2014 | 6,500,000 | |||||||||||||||||||||
Capital leases, due 2015 | 6,500,000 | |||||||||||||||||||||
Capital leases, due 2016 | 6,500,000 | |||||||||||||||||||||
Capital leases, due 2017 | 6,500,000 | |||||||||||||||||||||
Capital leases, due 2018 | 6,500,000 | |||||||||||||||||||||
Capital leases, due 2019 and thereafter | 6,500,000 | |||||||||||||||||||||
Deposit Liability, Current | 150,000,000 | |||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 1,172,715,000 | 1,095,352,000 | ||||||||||||||||||||
Deposit Received | 150,000,000 | 75,000,000 | 50,000,000 | 50,000,000 | 75,000,000 | |||||||||||||||||
Maximum Period to Refund Deposit upon Termination of Asset Purchase Agreement | 15 days | |||||||||||||||||||||
Unused credit with banks | 300,000,000 | |||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | 40,100,000 | |||||||||||||||||||||
Long-term Pollution Control Bond, Current | 0 | 11,300,000 | ||||||||||||||||||||
Redemption price of redeemable preferred stock, as a percent of liquidation amount | 100.00% | |||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.25% | |||||||||||||||||||||
Mississippi Power [Member] | Kemper IGCC [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | 80,000,000 | |||||||||||||||||||||
Mississippi Power [Member] | Plant Daniel Units 3 and 4 [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Revenue bond obligations face value | 270,000,000 | |||||||||||||||||||||
Significant Acquisitions and Disposals, Acquisition Costs, Assumption of Debt, at Fair Value | 346,100,000 | |||||||||||||||||||||
Fair value adjustment at date of purchase | 76,100,000 | |||||||||||||||||||||
Mississippi Power [Member] | Series 1999A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 7.13% | |||||||||||||||||||||
Mississippi Power [Member] | Revenue Bonds [Member] | Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 22,870,000 | 12,300,000 | 10,500,000 | |||||||||||||||||||
Debt Instrument, Face Amount, Authorized to Issue | 33,750,000 | |||||||||||||||||||||
Mississippi Power [Member] | Revenue Bonds [Member] | Mississippi Business Finance Corporation Taxable Revenue Bonds, Series 2012B [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 11,250,000 | 11,250,000 | ||||||||||||||||||||
Debt Instrument, Face Amount, Authorized to Issue | 11,250,000 | |||||||||||||||||||||
Mississippi Power [Member] | Capital Lease Obligations [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.90% | |||||||||||||||||||||
Southern Company And Subsidiaries [Member] | Senior Notes [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Debt Instrument, Face Amount | 1,400,000,000 | |||||||||||||||||||||
Alabama Power and Gulf Power [Member] | Secured Debt [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 41,000,000 | |||||||||||||||||||||
Traditional Operating Companies [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Pollution control revenue bonds, outstanding | 3,200,000,000 | 3,200,000,000 | ||||||||||||||||||||
Alabama Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Proceeds from issuance of junior subordinated notes | 206,000,000 | 206,000,000 | ||||||||||||||||||||
Senior Notes And Pollution Control Revenue Bonds, Current | 454,000,000 | |||||||||||||||||||||
Other Long-term Debt | 1,151,000,000 | 1,151,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 400,000,000 | 400,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 200,000,000 | 200,000,000 | ||||||||||||||||||||
Long-term debt maturities, 2016 | 525,000,000 | 525,000,000 | ||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 200,000,000 | 200,000,000 | ||||||||||||||||||||
Issuance Of Pollution Control Bond | 254,000,000 | |||||||||||||||||||||
Repayments of Pollution Control Bond | 254,000,000 | 0 | 1,000,000 | |||||||||||||||||||
Ratio of indebtedness to capitalization, debt covenant, required | 65.00% | |||||||||||||||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 14.00% | |||||||||||||||||||||
Pollution control revenue bonds, outstanding | 1,200,000,000 | 1,200,000,000 | ||||||||||||||||||||
Derivative, Notional Amount | 200,000,000 | |||||||||||||||||||||
Capitalized lease obligations | 5,000,000 | 5,000,000 | ||||||||||||||||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment | 8,522,000,000 | 8,114,000,000 | ||||||||||||||||||||
Unused credit with banks | 1,308,000,000 | |||||||||||||||||||||
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support | 784,000,000 | |||||||||||||||||||||
Pollution Control Revenue Bonds Required To Be Remarketed | 280,000,000 | |||||||||||||||||||||
Short-term debt outstanding, regulatory approved maximum | 2,000,000,000 | |||||||||||||||||||||
Commitment fee percentage (less than 1/4 of 1%) | 0.10% | |||||||||||||||||||||
Alabama Power [Member] | Natural Gas Pipeline [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Capitalized lease obligations | 5,000,000 | 5,000,000 | ||||||||||||||||||||
Alabama Power [Member] | Trust Preferred Securities Subject to Mandatory Redemption [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Preferred securities, outstanding | 200,000,000 | 200,000,000 | ||||||||||||||||||||
Alabama Power [Member] | Senior Notes And Pollution Control Bond [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months | 454,000,000 | |||||||||||||||||||||
Long-term debt maturities, 2016 | 200,000,000 | |||||||||||||||||||||
Long-term debt maturities, 2016 | 561,000,000 | |||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Five | 200,000,000 | |||||||||||||||||||||
Long-term Debt, Maturities, Repayments of Principal in Year Four | 0 | |||||||||||||||||||||
Alabama Power [Member] | Series 2014A [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 4.15% | |||||||||||||||||||||
Alabama Power [Member] | Series 2014DD [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 5.65% | |||||||||||||||||||||
Alabama Power [Member] | Multiple Bonds [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Repayments of Pollution Control Bond | 254,000,000 | |||||||||||||||||||||
Alabama Power [Member] | Capital Lease Obligations [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Fixed stated interest rate of debt obligation | 6.90% | 6.90% | ||||||||||||||||||||
Alabama Power [Member] | Unsecured Debt [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Redemption Amount of Principal Notes | 250,000,000 | 400,000,000 | ||||||||||||||||||||
Senior Notes outstanding | 5,300,000,000 | 4,900,000,000 | ||||||||||||||||||||
Notes due April 30, 2033 [Member] | Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Promissory Note | 800,000 | |||||||||||||||||||||
Notes due September 30, 2032 [Member] | Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Promissory Note | 100,000 | |||||||||||||||||||||
Debt Due April Thirtieth Two Thousand Thirty Four [Member] | Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Promissory Note | 3,900,000 | |||||||||||||||||||||
Debt Due May Thirty First Two Thousand Thirty Four [Member] | Southern Power [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Promissory Note | 5,400,000 | |||||||||||||||||||||
Capital Lease Obligations [Member] | Georgia Power [Member] | Secured Debt [Member] | ||||||||||||||||||||||
Financing (Textual) [Abstract] | ||||||||||||||||||||||
Long-term Debt | $1,200,000,000 |
Commitments_Estimated_Longterm
Commitments - Estimated Long-term obligations (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | $100,000,000 | |
2016 | 89,000,000 | |
2017 | 65,000,000 | |
2018 | 44,000,000 | |
2019 | 29,000,000 | |
2020 and thereafter | 248,000,000 | |
Total | 575,000,000 | |
Alabama Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 16,000,000 | |
2016 | 14,000,000 | |
2017 | 10,000,000 | |
2018 | 6,000,000 | |
2019 | 5,000,000 | |
2020 and thereafter | 17,000,000 | |
Total | 68,000,000 | |
Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 25,000,000 | |
2016 | 20,000,000 | |
2017 | 16,000,000 | |
2018 | 10,000,000 | |
2019 | 5,000,000 | |
2020 and thereafter | 14,000,000 | |
Total | 90,000,000 | |
Capital And Operating Leases, Future Minimum Payments Due, Next Twelve Months | 237,000,000 | |
Capital And Operating Leases, Future Minimum Payments Due In Two Years | 250,000,000 | |
Capital And Operating Leases, Future Minimum Payments Due In Three Years | 250,000,000 | |
Capital And Operating Leases, Future Minimum Payments Due In Four Years | 242,000,000 | |
Capital And Operating Leases, Future Minimum Payments Due In Five Years | 244,000,000 | |
Capital And Operating Leases, Future Minimum Payments Due Thereafter | 2,483,000,000 | |
Capital And Operating Leases, Future Minimum Payments Due | 3,706,000,000 | |
Minimum Lease Payments, Capital Leases [Abstract] | ||
Capital Leases, Future Minimum Payments, Lesser Of Fair Value and Present Value | 149,000,000 | |
Period Of Service For Gas Transportation Supplier | 1 year | |
Gulf Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 15,200,000 | |
2016 | 15,100,000 | |
2017 | 1,500,000 | |
Total | 31,800,000 | |
Railcars [Member] | Alabama Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 13,000,000 | |
2016 | 11,000,000 | |
2017 | 7,000,000 | |
2018 | 5,000,000 | |
2019 | 5,000,000 | |
2020 and thereafter | 17,000,000 | |
Total | 58,000,000 | |
Vehicles And Other [Member] | Alabama Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 3,000,000 | |
2016 | 3,000,000 | |
2017 | 3,000,000 | |
2018 | 1,000,000 | |
2019 | 0 | |
2020 and thereafter | 0 | |
Total | 10,000,000 | |
Barges and Rail Cars [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 50,000,000 | |
2016 | 41,000,000 | |
2017 | 18,000,000 | |
2018 | 9,000,000 | |
2019 | 6,000,000 | |
2020 and thereafter | 20,000,000 | |
Total | 144,000,000 | |
Barges and Rail Cars [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 18,000,000 | |
2016 | 13,000,000 | |
2017 | 9,000,000 | |
2018 | 4,000,000 | |
2019 | 1,000,000 | |
2020 and thereafter | 3,000,000 | |
Total | 48,000,000 | |
Barges and Rail Cars [Member] | Gulf Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 15,100,000 | |
2016 | 15,000,000 | |
2017 | 1,400,000 | |
Total | 31,500,000 | |
Other Lease Payments [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 50,000,000 | |
2016 | 48,000,000 | |
2017 | 47,000,000 | |
2018 | 35,000,000 | |
2019 | 23,000,000 | |
2020 and thereafter | 228,000,000 | |
Total | 431,000,000 | |
Other Lease Payments [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 7,000,000 | |
2016 | 7,000,000 | |
2017 | 7,000,000 | |
2018 | 6,000,000 | |
2019 | 4,000,000 | |
2020 and thereafter | 11,000,000 | |
Total | 42,000,000 | |
Other Lease Payments [Member] | Gulf Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 100,000 | |
2016 | 100,000 | |
2017 | 100,000 | |
Total | 300,000 | |
Purchased Power [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2015 | 230,000,000 | |
2016 | 234,000,000 | |
2017 | 264,000,000 | |
2018 | 270,000,000 | |
2019 | 274,000,000 | |
2020 and thereafter | 1,980,000,000 | |
Total | 3,252,000,000 | |
Purchased Power [Member] | Alabama Power [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2015 | 37,000,000 | |
2016 | 39,000,000 | |
2017 | 40,000,000 | |
2018 | 41,000,000 | |
2019 | 43,000,000 | |
2020 and thereafter | 137,000,000 | |
Total | 337,000,000 | |
Purchased Power [Member] | Gulf Power [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2015 | 78,700,000 | |
2016 | 78,700,000 | |
2017 | 78,800,000 | |
2018 | 78,900,000 | |
2019 | 78,900,000 | |
2020 and thereafter | 270,300,000 | |
Total | 664,300,000 | |
Other Lease Payments [Member] | ||
Recorded Unconditional Purchase Obligation, Fiscal Year Maturity Schedule [Abstract] | ||
2015 | 11,000,000 | |
2016 | 11,000,000 | |
2017 | 10,000,000 | |
2018 | 7,000,000 | |
2019 | 6,000,000 | |
2020 and thereafter | 50,000,000 | |
Total | 95,000,000 | |
Affiliate Capital Lease PPA [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Capital Leases [Abstract] | ||
2015 | 22,000,000 | |
2016 | 22,000,000 | |
2017 | 23,000,000 | |
2018 | 23,000,000 | |
2019 | 23,000,000 | |
2020 and thereafter | 255,000,000 | |
Total | 368,000,000 | |
Less: amounts representing executory costs | 55,000,000 | [1] |
Net minimum lease payments | 313,000,000 | |
Less: amounts representing interest | 85,000,000 | [2] |
Present value of net minimum lease payments | 228,000,000 | [3] |
Affiliate Operating Lease PPA [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 90,000,000 | |
2016 | 100,000,000 | |
2017 | 71,000,000 | |
2018 | 62,000,000 | |
2019 | 63,000,000 | |
2020 and thereafter | 606,000,000 | |
Total | 992,000,000 | |
Non-Affiliate Operating Lease PPA [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 114,000,000 | [4] |
2016 | 117,000,000 | [4] |
2017 | 146,000,000 | [4] |
2018 | 150,000,000 | [4] |
2019 | 152,000,000 | [4] |
2020 and thereafter | 1,572,000,000 | [4] |
Total | 2,251,000,000 | [4] |
Minimum Lease Payments, Capital Leases [Abstract] | ||
Biomass PPAs Amount | 1,100,000,000 | |
Plant Vogtle Nuclear Units 1 and 2 [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Operating Leases [Abstract] | ||
2015 | 11,000,000 | |
2016 | 11,000,000 | |
2017 | 10,000,000 | |
2018 | 7,000,000 | |
2019 | 6,000,000 | |
2020 and thereafter | 50,000,000 | |
Total | $95,000,000 | |
Plant McIntosh [Member] | Georgia Power [Member] | ||
Minimum Lease Payments, Capital Leases [Abstract] | ||
Period Of Service For Gas Transportation Supplier | 15 years | |
[1] | Executory costs such as taxes, maintenance, and insurance (including the estimated profit thereon) are estimated and included in total minimum lease payments. | |
[2] | Amount necessary to reduce minimum lease payments to present value calculated at the Company's incremental borrowing rate at the inception of the leases. | |
[3] | Once service commences under the PPAs beginning in 2015, the Company will recognize capital lease assets and capital lease obligations totaling $149 million, being the lesser of the estimated fair value of the lease property or the present value of the net minimum lease payments. | |
[4] | A total of $1.1 billion of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. |
Commitments_Details
Commitments (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | $6,005,000,000 | $5,510,000,000 | $5,057,000,000 | |
Expense Under Purchase Power Agreements Accounted For As Operating Leases | 198,000,000 | 157,000,000 | 171,000,000 | |
Operating Leases, Rent Expense | 118,000,000 | 123,000,000 | 155,000,000 | |
Leasing commitment, 2015 | 100,000,000 | |||
Leasing commitment, 2016 | 89,000,000 | |||
Leasing commitment, 2017 | 65,000,000 | |||
Leasing commitment, 2018 | 44,000,000 | |||
Leasing commitment, 2019 | 29,000,000 | |||
Leasing commitment, 2020 and thereafter | 248,000,000 | |||
Operating leases, future minimum lease payments due | 575,000,000 | |||
Senior Notes | 18,200,000,000 | 17,300,000,000 | ||
Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2015 | 50,000,000 | |||
Leasing commitment, 2016 | 41,000,000 | |||
Leasing commitment, 2017 | 18,000,000 | |||
Leasing commitment, 2018 | 9,000,000 | |||
Leasing commitment, 2019 | 6,000,000 | |||
Leasing commitment, 2020 and thereafter | 20,000,000 | |||
Operating leases, future minimum lease payments due | 144,000,000 | |||
Alabama Power and Georgia Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating leases, future minimum lease payments due | 53,000,000 | |||
Alabama Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | 1,605,000,000 | 1,631,000,000 | 1,503,000,000 | |
Expense Under Purchase Power Agreements Accounted For As Operating Leases | 37,000,000 | 30,000,000 | 33,000,000 | |
Jointly Owned Utility Plant, Proportionate Ownership Share | 14.00% | |||
Operating Leases, Rent Expense | 18,000,000 | 21,000,000 | 24,000,000 | |
Leasing commitment, 2015 | 16,000,000 | |||
Leasing commitment, 2016 | 14,000,000 | |||
Leasing commitment, 2017 | 10,000,000 | |||
Leasing commitment, 2018 | 6,000,000 | |||
Leasing commitment, 2019 | 5,000,000 | |||
Leasing commitment, 2020 and thereafter | 17,000,000 | |||
Operating leases, future minimum lease payments due | 68,000,000 | |||
Long-term pollution control bonds | 1,200,000,000 | 1,200,000,000 | ||
Alabama Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating Leases, Rent Expense | 14,000,000 | 18,000,000 | 19,000,000 | |
Alabama Power [Member] | Residual Value, Leased Property [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2015 | 5,000,000 | |||
Leasing commitment, 2016 | 4,000,000 | |||
Leasing commitment, 2019 | 0 | |||
Leasing commitment, 2020 and thereafter | 12,000,000 | |||
Georgia Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Capital Leases, Future Minimum Payments, Lesser Of Fair Value and Present Value | 149,000,000 | |||
Fuel expense | 2,547,000,000 | 2,307,000,000 | 2,051,000,000 | |
Capacity Payments | 19,000,000 | 27,000,000 | 50,000,000 | |
Deferred capacity expense | 167,000,000 | 162,000,000 | 169,000,000 | |
Operating Leases, Rent Expense | 28,000,000 | 32,000,000 | 34,000,000 | |
Percentage Of Minimum Lease Payments | 100.00% | |||
Leasing commitment, 2015 | 25,000,000 | |||
Leasing commitment, 2016 | 20,000,000 | |||
Leasing commitment, 2017 | 16,000,000 | |||
Leasing commitment, 2018 | 10,000,000 | |||
Leasing commitment, 2019 | 5,000,000 | |||
Leasing commitment, 2020 and thereafter | 14,000,000 | |||
Operating leases, future minimum lease payments due | 90,000,000 | |||
Long-term pollution control bonds | 1,600,000,000 | 1,700,000,000 | ||
Senior Notes | 6,900,000,000 | |||
Period Of Service For Gas Transportation Supplier | 1 year | |||
Guarantor Obligations, Maximum Exposure, Undiscounted | 43,000,000 | |||
Georgia Power [Member] | Plant McIntosh [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Period Of Service For Gas Transportation Supplier | 15 years | |||
Georgia Power [Member] | MEAG Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 5.00% | |||
Georgia Power [Member] | Alabama Power [Member] | Payment Guarantee [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Long-term pollution control bonds | 25,000,000 | |||
Georgia Power [Member] | Alabama Power [Member] | Financial Guarantee [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Senior Notes | 100,000,000 | |||
Georgia Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2015 | 18,000,000 | |||
Leasing commitment, 2016 | 13,000,000 | |||
Leasing commitment, 2017 | 9,000,000 | |||
Leasing commitment, 2018 | 4,000,000 | |||
Leasing commitment, 2019 | 1,000,000 | |||
Leasing commitment, 2020 and thereafter | 3,000,000 | |||
Operating leases, future minimum lease payments due | 48,000,000 | |||
Georgia Power [Member] | Residual Value, Leased Property [Member] | 2018 [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating leases, future minimum lease payments due | 32,000,000 | |||
Gulf Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | 604,641,000 | 532,791,000 | 544,936,000 | |
Expense Under Purchase Power Agreements Accounted For As Operating Leases | 49,500,000 | 21,300,000 | 24,600,000 | |
Deferred capacity expense | 163,077,000 | 180,149,000 | ||
Operating Leases, Rent Expense | 15,000,000 | 18,000,000 | 20,100,000 | |
Leasing commitment, 2015 | 15,200,000 | |||
Leasing commitment, 2016 | 15,100,000 | |||
Leasing commitment, 2017 | 1,500,000 | |||
Operating leases, future minimum lease payments due | 31,800,000 | |||
Long-term pollution control bonds | 309,000,000 | 296,000,000 | ||
Senior Notes | 1,070,000,000 | 945,000,000 | ||
Gulf Power [Member] | Plant Daniel [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Long-term pollution control bonds | 41,000,000 | |||
Gulf Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Leasing commitment, 2015 | 15,100,000 | |||
Leasing commitment, 2016 | 15,000,000 | |||
Leasing commitment, 2017 | 1,400,000 | |||
Operating leases, future minimum lease payments due | 31,500,000 | |||
Gulf Power [Member] | Barges and Rail Cars [Member] | Plant Daniel [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel cost recovery clause | 2,800,000 | 3,100,000 | 3,600,000 | |
Leasing commitment, 2015 | 1,600,000 | |||
Leasing commitment, 2016 | 1,600,000 | |||
Leasing commitment, 2017 | 1,600,000 | |||
Leasing commitment, 2018 | 0 | |||
Leasing commitment, 2020 and thereafter | 0 | |||
Mississippi Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | 573,936,000 | 491,250,000 | 411,226,000 | |
Term of Management Fee Contract | 40 years | |||
Management fee | 38,400,000 | |||
Operating Leases, Rent Expense | 12,700,000 | 10,100,000 | 11,100,000 | |
Number of Railcars Used Under Operating Lease | 229 | |||
Company's share of the leases | 50.00% | |||
Fuel cost recovery clause | 4,900,000 | 3,100,000 | 3,600,000 | |
Long-term pollution control bonds | 82,700,000 | 82,700,000 | ||
Senior Notes | 1,100,000,000 | 1,100,000,000 | ||
Mississippi Power [Member] | Plant Daniel [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Company's share of the leases | 50.00% | |||
Mississippi Power [Member] | Plant Watson [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Company's share of the leases | 100.00% | |||
Mississippi Power [Member] | Barges and Rail Cars [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Average leasing commitment, 2015 | 1,600,000 | |||
Average leasing commitment, 2016 | 1,600,000 | |||
Average leasing commitment, 2017 | 1,600,000 | |||
Average leasing commitment, 2018 | 0 | |||
Mississippi Power [Member] | Fuel Handling Equipment [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating Leases, Rent Expense | 200,000 | 200,000 | 200,000 | |
Leasing commitment, 2015 | 100,000 | |||
Mississippi Power [Member] | Barge Transportation [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Operating Leases, Rent Expense | 7,500,000 | 6,700,000 | 7,300,000 | |
Leasing commitment, 2015 | 1,800,000 | |||
Southern Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Fuel expense | 596,319,000 | 473,805,000 | 426,257,000 | |
Operating Leases, Rent Expense | 4,000,000 | 1,900,000 | 800,000 | |
Leasing commitment, 2015 | 4,500,000 | |||
Leasing commitment, 2016 | 4,500,000 | |||
Leasing commitment, 2017 | 4,600,000 | |||
Leasing commitment, 2018 | 4,600,000 | |||
Leasing commitment, 2019 | 4,700,000 | |||
Leasing commitment, 2020 and thereafter | 157,200,000 | |||
Senior Notes | 1,600,000,000 | |||
Non-Affiliate Operating Lease PPA [Member] | Georgia Power [Member] | ||||
Recorded Unconditional Purchase Obligation [Line Items] | ||||
Biomass PPAs Amount | 1,100,000,000 | |||
Leasing commitment, 2015 | 114,000,000 | [1] | ||
Leasing commitment, 2016 | 117,000,000 | [1] | ||
Leasing commitment, 2017 | 146,000,000 | [1] | ||
Leasing commitment, 2018 | 150,000,000 | [1] | ||
Leasing commitment, 2019 | 152,000,000 | [1] | ||
Leasing commitment, 2020 and thereafter | 1,572,000,000 | [1] | ||
Operating leases, future minimum lease payments due | $2,251,000,000 | [1] | ||
[1] | A total of $1.1 billion of biomass PPAs included under the non-affiliate operating leases is contingent upon the counterparties meeting specified contract dates for commercial operation and may change as a result of regulatory action. |
Common_Stock_and_Stock_Compens2
Common Stock and Stock Compensation - Stock Options, Assumptions Used (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted | |||
Expected volatility | 14.60% | 16.60% | 17.70% |
Expected term (in years) | 5 years | 5 years | 5 years |
Interest rate | 1.50% | 0.90% | 0.90% |
Dividend yield, percentage | 4.90% | 4.40% | 4.20% |
Weighted average grant-date fair value (in dollars per share) | $2.20 | $2.93 | $3.39 |
Performance Share Plan [Member] | |||
Assumptions used in the pricing model and the weighted average grant-date fair value of stock options granted | |||
Expected volatility | 12.60% | 12.00% | 16.00% |
Expected term (in years) | 3 years | 3 years | 3 years |
Interest rate | 0.60% | 0.40% | 0.40% |
Dividend yield | $2.03 | $1.96 | $1.89 |
Weighted average grant-date fair value (in dollars per share) | $37.54 | $40.50 | $41.99 |
Common_Stock_and_Stock_Compens3
Common Stock and Stock Compensation - Stock Option Activity (Details) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |
Shares Subject to Option, Outstanding, Beginning Balance | 38,819,366 |
Shares Subject to Option, Granted | 12,812,691 |
Shares Subject to Option, Exercised | -11,585,363 |
Shares Subject to Options, Cancelled | -117,375 |
Shares Subject to Option, Outstanding, Ending Balance | 39,929,319 |
Shares Subject to Options, Exercisable, Ending Balance | 20,695,310 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward] | |
Options Outstanding, Weighted Average Exercise Price, Beginning of Period (in dollars per share) | $38.64 |
Options Granted, Weighted Average Exercise Price (in dollars per share) | $41.40 |
Options Exercised, Weighted Average Exercise Price (in dollars per share) | $35.06 |
Options Cancelled, Weighted Average Exercise Price (in dollars per share) | $42.72 |
Options Outstanding, Weighted Average Exercise Price, End of Period (in dollars per share) | $40.55 |
Options Exercisable, Weighted Average Exercise Price, End of Period (in dollars per share) | $38.76 |
Common_Stock_and_Stock_Compens4
Common Stock and Stock Compensation - Shares Used to Compute Diluted Earnings Per Share (Details) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Earnings per share (EPS) b | |||
As reported shares | 897 | 877 | 871 |
Effect of options | 4 | 4 | 8 |
Diluted shares | 901 | 881 | 879 |
Common_Stock_and_Stock_Compens5
Common Stock and Stock Compensation - Textual (Details) (USD $) | 12 Months Ended | 14 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2014 | |
Employee | ||||
Share-based Compensation [Abstract] | ||||
Stock Issued During Period, Shares, Southern Investment Plan and employee and director stock plans | 20,800,000 | |||
Stock Issued During Period, Value, Southern Investment Plan and employee and director stock plans | $806,000,000 | |||
Common Stock Shares Issued Previously Held In Treasury | 5,000,000 | |||
Share-based compensation arrangement by Share-based payment award, number of shares reserved for issuance, pursuant to Stock-based compensation plan | 93,000,000 | |||
Number of employees participating in stock option program | 5,437 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | 12,812,691 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $2.20 | $2.93 | $3.39 | |
Weighted average remaining contractual term for options outstanding | 7 years | |||
Weighted average remaining contractual term for options exercisable | 6 years | |||
Aggregate intrinsic value for options outstanding | 342,000,000 | |||
Aggregate intrinsic value for options exercisable | 214,000,000 | |||
Total unrecognized compensation cost related to award | 10,000,000 | |||
Total compensation cost for award recognized in income | 27,000,000 | 25,000,000 | 23,000,000 | |
Total compensation cost for award recognized in income, tax benefit | 10,000,000 | 10,000,000 | 9,000,000 | |
Total intrinsic value of options exercised | 125,000,000 | 77,000,000 | 162,000,000 | |
Actual tax benefit for the tax deduction from stock option exercised | 48,000,000 | 30,000,000 | 62,000,000 | |
Cash received from issuance related to option exercise | 400,000,000 | 204,000,000 | 397,000,000 | |
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 7,000,000 | 16,000,000 | ||
Undistributed retained earnings of the subsidiaries | 6,400,000,000 | |||
Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Total unrecognized compensation cost related to award, weighted average period | 16 months | |||
Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $37.54 | $40.50 | $41.99 | |
Total unrecognized compensation cost related to award | 37,000,000 | |||
Total unrecognized compensation cost related to award, weighted average period | 20 months | |||
Total compensation cost for award recognized in income | 33,000,000 | 31,000,000 | 28,000,000 | |
Total compensation cost for award recognized in income, tax benefit | 13,000,000 | 12,000,000 | 11,000,000 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Performance share units, unvested | 1,830,381 | 1,643,759 | ||
Performance share units, granted | 1,057,813 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | 755,716 | |||
Performance unit shares, forfeited | 115,475 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number | 105,783 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price (in dollars per share) | $49.71 | |||
Maximum [Member] | ||||
Share-based Compensation [Abstract] | ||||
Stock Repurchase Program, Remaining Number of Shares Authorized to be Repurchased | 20,000,000 | |||
Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Southern Company Common Stock [Member] | ||||
Share-based Compensation [Abstract] | ||||
Remaining shares available for awards | 15,000,000 | |||
Georgia Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number of employees participating in stock option program | 1,000 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | 2,034,150 | 1,509,662 | 1,269,725 | |
Aggregate intrinsic value for options outstanding | 73,000,000 | |||
Aggregate intrinsic value for options exercisable | 51,000,000 | |||
Total intrinsic value of options exercised | 19,000,000 | 16,000,000 | 34,000,000 | |
Actual tax benefit for the tax deduction from stock option exercised | 7,000,000 | 6,000,000 | 13,000,000 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Georgia Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Performance share units, granted | 176,224 | 161,240 | 152,812 | |
Georgia Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $2.20 | $2.93 | $3.39 | |
Georgia Power [Member] | Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Total unrecognized compensation cost related to award | 7,000,000 | |||
Total unrecognized compensation cost related to award, weighted average period | 20 months | |||
Total compensation cost for award recognized in income | 6,000,000 | 6,000,000 | 6,000,000 | |
Total compensation cost for award recognized in income, tax benefit | 2,000,000 | 2,000,000 | 2,000,000 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $37.54 | $40.50 | $41.99 | |
Georgia Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Mississippi Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | 578,256 | 345,830 | 278,709 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Mississippi Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Total unrecognized compensation cost related to award | 1,800,000 | |||
Total unrecognized compensation cost related to award, weighted average period | 20 months | |||
Total compensation cost for award recognized in income | 1,700,000 | 1,500,000 | 1,200,000 | |
Total compensation cost for award recognized in income, tax benefit | 600,000 | 600,000 | 400,000 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Performance share units, granted | 49,579 | 36,769 | 33,077 | |
Mississippi Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number of employees participating in stock option program | 244 | |||
Option expiration period from date of grant | 10 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $2.20 | $2.93 | $3.39 | |
Aggregate intrinsic value for options outstanding | 18,400,000 | |||
Aggregate intrinsic value for options exercisable | 12,300,000 | |||
Total intrinsic value of options exercised | 5,400,000 | 2,700,000 | 4,900,000 | |
Actual tax benefit for the tax deduction from stock option exercised | 2,100,000 | 1,100,000 | 1,900,000 | |
Mississippi Power [Member] | Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $37.54 | $40.50 | $41.99 | |
Mississippi Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Alabama Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number of employees participating in stock option program | 1,000 | |||
Aggregate intrinsic value for options outstanding | 55,000,000 | |||
Aggregate intrinsic value for options exercisable | 37,000,000 | |||
Total unrecognized compensation cost related to award | 1,000,000 | |||
Total unrecognized compensation cost related to award, weighted average period | 15 months | |||
Total compensation cost for award recognized in income | 5,000,000 | 4,000,000 | 4,000,000 | |
Total compensation cost for award recognized in income, tax benefit | 2,000,000 | 2,000,000 | 1,000,000 | |
Total intrinsic value of options exercised | 21,000,000 | 11,000,000 | 28,000,000 | |
Actual tax benefit for the tax deduction from stock option exercised | 8,000,000 | 4,000,000 | 11,000,000 | |
Alabama Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Total unrecognized compensation cost related to award | 5,000,000 | |||
Total unrecognized compensation cost related to award, weighted average period | 20 months | |||
Total compensation cost for award recognized in income | 5,000,000 | 0 | 0 | |
Total compensation cost for award recognized in income, tax benefit | 2,000,000 | 0 | 0 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Performance share units, granted | 176,070 | 141,355 | 131,820 | |
Alabama Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | 2,027,298 | 1,319,038 | 1,099,315 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value (in dollars per share) | $2.20 | $2.93 | $3.39 | |
Alabama Power [Member] | Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $37.54 | $40.50 | $41.99 | |
Alabama Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years | |||
Gulf Power [Member] | ||||
Share-based Compensation [Abstract] | ||||
Number of employees participating in stock option program | 195 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures | 432,371 | 285,209 | 244,607 | |
Share Based Compensation Arrangement by Share Based Payment Award Fair Value Assumptions Weighted Average Grant Date Fair Value | 2.2 | 2.93 | 3.39 | |
Aggregate intrinsic value for options outstanding | 11,900,000 | |||
Aggregate intrinsic value for options exercisable | 7,700,000 | |||
Total intrinsic value of options exercised | 5,200,000 | 1,700,000 | 3,800,000 | |
Actual tax benefit for the tax deduction from stock option exercised | 2,000,000 | 600,000 | 1,500,000 | |
Vesting period of performance share units issued under Performance Share Plan | 3 years | |||
Minimum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 0.00% | |||
Maximum Percentage of transfer performance shares to common stock based on actual Total Shareholder Return | 200.00% | |||
Gulf Power [Member] | Performance Shares [Member] | ||||
Share-based Compensation [Abstract] | ||||
Total unrecognized compensation cost related to award | 1,300,000 | |||
Total compensation cost for award recognized in income | 1,000,000 | 1,000,000 | ||
Total compensation cost for award recognized in income, tax benefit | 400,000 | 400,000 | 400,000 | |
Gulf Power [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Option expiration period from date of grant | 10 years | |||
Gulf Power [Member] | Performance Share Plan [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Fair Value Assumptions Weighted Average Grant Date Fair Value | $37.54 | $40.50 | $41.99 | |
Total unrecognized compensation cost related to award, weighted average period | 20 months | |||
Performance share units, granted | 37,829 | 30,627 | 29,444 | |
Gulf Power [Member] | Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation [Abstract] | ||||
Share Based Compensation Arrangement by Share Based Payment Award Exercisable Period | 3 years |
Nuclear_Insurance_Details
Nuclear Insurance (Details) (USD $) | 1 Months Ended | 12 Months Ended |
Apr. 30, 2014 | Dec. 31, 2014 | |
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act | $13,600,000,000 | |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 375,000,000 | |
Maximum amount that a company could be assessed per incident for each licensed reactor | 127,000,000 | |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | 19,000,000 | |
Block period considered for inflation adjustment against maximum assessment per reactor | 5 years | |
Maximum deductible waiting period | 26 weeks | |
Maximum coverage per occurrence per unit limit to obtain replacement power | 490,000,000 | |
Approximate period over which maximum per occurrence per unit limit is exhausted | 3 years | |
Aggregate payment for claims resulting from terrorist acts in one year period | 3,200,000,000 | |
Vogtle Units 3 and 4 [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum limits for accidental property damage occurring during construction | 2,750,000,000 | |
Alabama Power [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act | 13,600,000,000 | |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 375,000,000 | |
Maximum amount that a company could be assessed per incident for each licensed reactor | 127,000,000 | |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | 19,000,000 | |
Maximum assessment, excluding any applicable state premium taxes | 255,000,000 | |
Maximum aggregate amount to be paid in one year | 38,000,000 | |
Block period considered for inflation adjustment against maximum assessment per reactor | 5 years | |
Block period considered for inflation adjustment against maximum yearly assessment | 5 years | |
Maximum property damage insurance provided to nuclear generating facilities | 1,500,000,000 | |
Maximum additional coverage provided for losses under excess insurance | 750,000,000 | 1,250,000,000 |
Maximum Sublimit Non-Nuclear Losses | 750,000,000 | |
Maximum deductible waiting period | 26 weeks | |
Maximum Deductible Waiting Period Days | 182 days | |
Maximum coverage per occurrence per unit limit to obtain replacement power | 490,000,000 | |
Approximate period over which maximum per occurrence per unit limit is exhausted | 3 years | |
Elected deductible waiting period | 12-week | |
Current maximum annual assessments under NEIL policies | 50,000,000 | |
Aggregate payment for claims resulting from terrorist acts in one year period | 3,200,000,000 | |
Elected Deductible Waiting Period, Days | 84 days | |
Georgia Power [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Amendments Act | 13,600,000,000 | |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 375,000,000 | |
Maximum amount that a company could be assessed per incident for each licensed reactor | 127,000,000 | |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | 19,000,000 | |
Maximum assessment, excluding any applicable state premium taxes | 247,000,000 | |
Maximum aggregate amount to be paid in one year | 37,000,000 | |
Block period considered for inflation adjustment against maximum assessment per reactor | 5 years | |
Block period considered for inflation adjustment against maximum yearly assessment | 5 years | |
Maximum property damage insurance provided to nuclear generating facilities | 1,500,000,000 | |
Maximum additional coverage provided for losses under excess insurance | 1,250,000,000 | |
Maximum Sublimit Non-Nuclear Losses | 750,000,000 | |
Maximum deductible waiting period | 26 weeks | |
Maximum coverage per occurrence per unit limit to obtain replacement power | 490,000,000 | |
Approximate period over which maximum per occurrence per unit limit is exhausted | 3 years | |
Elected deductible waiting period | 12-week | |
Current maximum annual assessments under NEIL policies | 72,000,000 | |
Aggregate payment for claims resulting from terrorist acts in one year period | 3,200,000,000 | |
Georgia Power [Member] | Vogtle Units 3 and 4 [Member] | ||
Jointly Owned Utility Plant Interests [Line Items] | ||
Maximum limits for accidental property damage occurring during construction | $2,750,000,000 |
Fair_Value_Measurements_Assets
Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
Assets: | ||||
Asset Derivatives | $21,000,000 | $27,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 225,000,000 | 56,000,000 | ||
Fair Value, Measurements, Recurring [Member] | ||||
Assets: | ||||
Interest rate derivatives | 8,000,000 | 3,000,000 | ||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 397,000,000 | 491,000,000 | ||
Other investments | 10,000,000 | 13,000,000 | ||
Fair value assets, total | 1,971,000,000 | 1,994,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 225,000,000 | |||
Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 668,000,000 | [1] | 664,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 218,000,000 | [1] | 231,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 130,000,000 | [1] | 103,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 62,000,000 | [1] | 64,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 299,000,000 | [1] | 229,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 139,000,000 | [1] | 132,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 27,000,000 | [1] | 40,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 13,000,000 | 24,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 201,000,000 | 56,000,000 | ||
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 24,000,000 | |||
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||||
Assets: | ||||
Interest rate derivatives | 0 | 0 | ||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 397,000,000 | 491,000,000 | ||
Other investments | 9,000,000 | 9,000,000 | ||
Fair value assets, total | 1,034,000,000 | 1,124,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 583,000,000 | [1] | 589,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 34,000,000 | [1] | 35,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 11,000,000 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Assets: | ||||
Interest rate derivatives | 8,000,000 | 3,000,000 | ||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Other investments | 0 | 0 | ||
Fair value assets, total | 933,000,000 | 863,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 225,000,000 | |||
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 85,000,000 | [1] | 75,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 184,000,000 | [1] | 196,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 130,000,000 | [1] | 103,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 62,000,000 | [1] | 64,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 299,000,000 | [1] | 229,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 139,000,000 | [1] | 132,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 13,000,000 | [1] | 37,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 13,000,000 | 24,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 201,000,000 | 56,000,000 | ||
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 24,000,000 | |||
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||||
Assets: | ||||
Interest rate derivatives | 0 | 0 | ||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Other investments | 1,000,000 | 4,000,000 | ||
Fair value assets, total | 4,000,000 | 7,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 3,000,000 | [1] | 3,000,000 | [1] |
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Alabama Power [Member] | ||||
Assets: | ||||
Asset Derivatives | 1,000,000 | 7,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 61,000,000 | 8,000,000 | ||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 162,000,000 | [2] | 236,000,000 | |
Fair value assets, total | 917,000,000 | 956,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 61,000,000 | |||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 486,000,000 | [2] | 466,000,000 | [3] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 97,000,000 | [2] | 100,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 34,000,000 | [2] | 24,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 111,000,000 | [2] | 89,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 18,000,000 | [2] | 18,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 8,000,000 | [2] | 16,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 1,000,000 | 7,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 53,000,000 | 8,000,000 | ||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 8,000,000 | |||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 162,000,000 | [2] | 236,000,000 | |
Fair value assets, total | 599,000,000 | 663,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 403,000,000 | [2] | 392,000,000 | [3] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 34,000,000 | [2] | 35,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | [2] | 0 | |
Fair value assets, total | 315,000,000 | 290,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 61,000,000 | |||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 83,000,000 | [2] | 74,000,000 | [3] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 63,000,000 | [2] | 65,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 34,000,000 | [2] | 24,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 111,000,000 | [2] | 89,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 18,000,000 | [2] | 18,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 5,000,000 | [2] | 13,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 1,000,000 | 7,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 53,000,000 | 8,000,000 | ||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 8,000,000 | |||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | [2] | 0 | |
Fair value assets, total | 3,000,000 | 3,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [3] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [2] | 0 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 3,000,000 | [2] | 3,000,000 | [2] |
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 755,000,000 | |||
Fair value assets, total | 802,000,000 | |||
Liabilities: | ||||
Liability Derivatives | 41,000,000 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 182,000,000 | [1] | 198,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 121,000,000 | [1] | 131,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 96,000,000 | [1] | 79,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 62,000,000 | [1] | 64,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 188,000,000 | [1] | 140,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 121,000,000 | [1] | 114,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 19,000,000 | [1] | 24,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 6,000,000 | [1] | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 7,000,000 | 5,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 27,000,000 | 21,000,000 | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 14,000,000 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 197,000,000 | |||
Fair value assets, total | 191,000,000 | |||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 180,000,000 | [1] | 197,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 11,000,000 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 558,000,000 | |||
Fair value assets, total | 611,000,000 | |||
Liabilities: | ||||
Liability Derivatives | 41,000,000 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 2,000,000 | [1] | 1,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 121,000,000 | [1] | 131,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 96,000,000 | [1] | 79,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 62,000,000 | [1] | 64,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 188,000,000 | [1] | 140,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 121,000,000 | [1] | 114,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 8,000,000 | [1] | 24,000,000 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 6,000,000 | [1] | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 7,000,000 | 5,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 27,000,000 | 21,000,000 | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 14,000,000 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | |||
Fair value assets, total | 0 | |||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity fund [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | 0 | [1] |
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||||
Nuclear decommissioning trusts: | ||||
Nuclear decommissioning trusts | 0 | [1] | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Contract [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 18,032,000 | 15,929,000 | ||
Fair value assets, total | 18,157,000 | 22,891,000 | ||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 125,000 | 6,962,000 | ||
Liabilities: | ||||
Liability Derivatives | 72,435,000 | 17,043,000 | ||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 18,032,000 | 15,929,000 | ||
Fair value assets, total | 18,032,000 | 15,929,000 | ||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Fair value assets, total | 125,000 | 6,962,000 | ||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 125,000 | 6,962,000 | ||
Liabilities: | ||||
Liability Derivatives | 72,435,000 | 17,043,000 | ||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Fair value assets, total | 0 | 0 | ||
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Mississippi Power [Member] | ||||
Assets: | ||||
Asset Derivatives | 52,000 | 4,803,000 | ||
Liabilities: | ||||
Liability Derivatives | 45,418,000 | 10,282,000 | ||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 114,900,000 | 125,000,000 | ||
Fair value assets, total | 114,965,000 | 129,803,000 | ||
Liabilities: | ||||
Fair value liabilities, total | 10,282,000 | |||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 65,000 | 4,803,000 | ||
Liabilities: | ||||
Liability Derivatives | 45,429,000 | 10,281,000 | ||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign currency derivatives [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 1,000 | |||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 114,900,000 | 125,000,000 | ||
Fair value assets, total | 114,900,000 | 125,000,000 | ||
Liabilities: | ||||
Fair value liabilities, total | 0 | |||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign currency derivatives [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Fair value assets, total | 65,000 | 4,803,000 | ||
Liabilities: | ||||
Fair value liabilities, total | 10,282,000 | |||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 65,000 | 4,803,000 | ||
Liabilities: | ||||
Liability Derivatives | 45,429,000 | 10,281,000 | ||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign currency derivatives [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 1,000 | |||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Fair value assets, total | 0 | 0 | ||
Liabilities: | ||||
Fair value liabilities, total | 0 | |||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | 0 | ||
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign currency derivatives [Member] | ||||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | ||||
Assets: | ||||
Asset Derivatives | 5,500,000 | |||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 18,000,000 | 68,000,000 | ||
Fair value assets, total | 23,500,000 | 68,600,000 | ||
Liabilities: | ||||
Liability Derivatives | 3,600,000 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 600,000 | |||
Liabilities: | ||||
Liability Derivatives | 600,000 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | |||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 18,000,000 | 68,000,000 | ||
Fair value assets, total | 18,000,000 | 68,000,000 | ||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | |||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Assets: | ||||
Asset Derivatives | 5,500,000 | |||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Fair value assets, total | 5,500,000 | 600,000 | ||
Liabilities: | ||||
Liability Derivatives | 3,600,000 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 600,000 | |||
Liabilities: | ||||
Liability Derivatives | 600,000 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | |||
Nuclear decommissioning trusts: | ||||
Cash equivalents | 0 | 0 | ||
Fair value assets, total | 0 | 0 | ||
Liabilities: | ||||
Liability Derivatives | 0 | |||
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Energy Related Derivative [Member] | ||||
Assets: | ||||
Asset Derivatives | 0 | |||
Liabilities: | ||||
Liability Derivatives | $0 | |||
[1] | Includes the investment securities pledged to creditors and collateral received, and excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases and the lending pool. See Note 1 under "Nuclear Decommissioning" for additional information. | |||
[2] | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. See Note 1 under "Nuclear Decommissioning" for additional information. | |||
[3] | Excludes receivables related to investment income, pending investment sales, and payables related to pending investment purchases. |
Fair_Value_Measurements_Fair_V
Fair Value Measurements - Fair Value, Nature and Risk of Investments (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Foreign equity fund [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | $121,000,000 | $131,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Monthly | Monthly |
Redemption Notice Period | 5 days | 5 days |
Corporate bonds - commingled funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 8,000,000 | |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | |
Redemption Notice Period | Not applicableB | |
Equity - commingled funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 63,000,000 | 65,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily/Monthly | Daily/Monthly |
Redemption Notice Period | Daily/7B daysB | Daily/7B daysB |
Debt - Commingled Funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 15,000,000 | |
Unfunded Commitments | 0 | |
Redemption Frequency | Daily | |
Redemption Notice Period | 5 days | |
Other - commingled funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 8,000,000 | 24,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | Not applicableB | Not applicableB |
Other - money market funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 11,000,000 | |
Unfunded Commitments | 0 | |
Redemption Frequency | Daily | |
Redemption Notice Period | Not applicable | |
Trust-owned life insurance [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 115,000,000 | 110,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | 15 daysB | 15 daysB |
Money market funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 397,000,000 | 491,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | Not applicableB | Not applicableB |
Maximum [Member] | Foreign equity fund [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Redemption Notice Period | 5 days | 5 days |
Maximum [Member] | Equity - commingled funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Redemption Notice Period | 7 days | 7 days |
Maximum [Member] | Debt - Commingled Funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Redemption Notice Period | 5 days | |
Maximum [Member] | Trust-owned life insurance [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Redemption Notice Period | 15 days | 15 days |
Alabama Power [Member] | Equity - commingled funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 63,000,000 | 65,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily/Monthly | Daily/Monthly |
Redemption Notice Period | Daily/7 days | Daily/7 days |
Redemption Notice Period | 7 days | 7 days |
Alabama Power [Member] | Debt - Commingled Funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 15,000,000 | |
Unfunded Commitments | 0 | |
Redemption Frequency | Daily | |
Redemption Notice Period | 5 days | |
Redemption Notice Period | 5 days | |
Alabama Power [Member] | Trust-owned life insurance [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 115,000,000 | 110,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | 15 days | 15 days |
Redemption Notice Period | 15 days | 15 days |
Alabama Power [Member] | Money market funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 162,000,000 | |
Cash and Cash Equivalents, Fair Value Disclosure | 236,000,000 | |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | Not applicable | Not applicable |
Georgia Power [Member] | Foreign equity fund [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 121,000,000 | 131,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Monthly | Daily |
Redemption Notice Period | 5 days | 5 days |
Georgia Power [Member] | Corporate bonds - commingled funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 8,000,000 | |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | |
Redemption Notice Period | Not applicable | |
Georgia Power [Member] | Other - commingled funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 8,000,000 | 24,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | Not applicable | Not applicable |
Georgia Power [Member] | Other - money market funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 11,000,000 | |
Unfunded Commitments | 0 | |
Redemption Frequency | Daily | |
Redemption Notice Period | Not applicable | |
Georgia Power [Member] | Money market funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Unfunded Commitments | 0 | |
Georgia Power [Member] | Maximum [Member] | Foreign equity fund [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Redemption Notice Period | 5 days | 5 days |
Gulf Power [Member] | Money market funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 18,032,000 | 15,929,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | Not applicable | Not applicable |
Mississippi Power [Member] | Money market funds [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 114,900,000 | 125,000,000 |
Unfunded Commitments | 0 | 0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | NotB applicable | Not applicable |
Southern Power [Member] | ||
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments | ||
Fair Value | 18,000,000 | 68,000,000 |
Unfunded Commitments | $0 | $0 |
Redemption Frequency | Daily | Daily |
Redemption Notice Period | Not applicable | Not applicable |
Fair_Value_Measurements_Financ
Fair Value Measurements - Financial Instruments, Carrying Amount Not Equal to Fair Value (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | $24,015,000 | $21,650,000 |
Long-term debt, Fair Value | 25,816,000 | 22,197,000 |
Alabama Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 6,631,000 | 6,228,000 |
Long-term debt, Fair Value | 7,321,000 | 6,534,000 |
Georgia Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 9,797,000 | 8,593,000 |
Long-term debt, Fair Value | 10,552,000 | 8,782,000 |
Gulf Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 1,369,594 | 1,233,163 |
Long-term debt, Fair Value | 1,476,954 | 1,261,889 |
Mississippi Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 2,328,476 | 2,098,639 |
Long-term debt, Fair Value | 2,382,050 | 2,045,519 |
Southern Power [Member] | ||
Long-term debt: | ||
Long-term debt, Carrying Amount | 1,621,000 | 1,620,000 |
Long-term debt, Fair Value | $1,785,000 | $1,660,000 |
Fair_Value_Measurements_Textua
Fair Value Measurements - Textual (Details) (Georgia Power [Member], USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Notices Of Withdrawal Foreign Equity Funds | 20.00% |
Minimum [Member] | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Withdrawal Of Foreign Equity Fund Investment | 1 |
Foreign Equity Fund Investment | 10 |
Maximum [Member] | |
Fair Value, Option, Quantitative Disclosures [Line Items] | |
Period Of Funds Maturity | 90 days |
Derivatives_EnergyRelated_Inte
Derivatives - Energy-Related, Interest Rate, and Foreign Currency Derivatives Information (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Oct. 31, 2014 | Dec. 31, 2013 | |
MMBTU | |||
Derivative [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | $21,000,000 | $27,000,000 | |
Derivative Liability, Fair Value, Gross Liability | 225,000,000 | 56,000,000 | |
Interest rate derivative contracts | |||
Notional Amount | 2,050,000,000 | ||
Fair Value Gain (Loss) | -16,000,000 | ||
Alabama Power [Member] | |||
Derivative [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 1,000,000 | 7,000,000 | |
Derivative Liability, Fair Value, Gross Liability | 61,000,000 | 8,000,000 | |
Energy-related derivative contracts | |||
Net Purchased mmBtu | 56,000,000 | ||
Longest Hedge Date | 2017 | ||
Interest rate derivative contracts | |||
Notional Amount | 200,000,000 | ||
Georgia Power [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 1,600,000,000 | ||
Fair Value Gain (Loss) | -9,000,000 | ||
Mississippi Power [Member] | |||
Derivative [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 52,000 | 4,803,000 | |
Derivative Liability, Fair Value, Gross Liability | 45,418,000 | 10,282,000 | |
Energy-related derivative contracts | |||
Net Purchased mmBtu | 54,000,000 | ||
Longest Hedge Date | 2018 | ||
Maturity Date October 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 200,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 2.93% | ||
Derivative, Maturity Date | 1-Oct-25 | ||
Fair Value Gain (Loss) | -8,000,000 | ||
Maturity Date October 2025 [Member] | Alabama Power [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 200,000,000 | ||
Derivative Interest Rate Received | 3-month B LIBOR | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 2.93% | ||
Derivative, Maturity Date | 1-Oct-25 | ||
Fair Value Gain (Loss) | -8,000,000 | ||
Maturity Date May 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 350,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 2.57% | ||
Derivative, Maturity Date | 1-May-25 | ||
Fair Value Gain (Loss) | -6,000,000 | ||
Maturity Date May 2025 [Member] | Georgia Power [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 350,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 2.57% | ||
Derivative, Maturity Date | 1-May-25 | ||
Fair Value Gain (Loss) | -6,000,000 | ||
Maturity Date March 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 250,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 0.32% | ||
Fair Value Hedges Weighted Average Interest Rate | 0.0075 | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 0.32% | ||
Derivative, Maturity Date | 1-Mar-16 | ||
Fair Value Gain (Loss) | 0 | ||
Maturity Date March 2016 [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 250,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 0.32% | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 0.75% | ||
Derivative, Maturity Date | 1-Mar-16 | ||
Fair Value Gain (Loss) | 0 | ||
Maturity Date March 2016 [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 0.32% | ||
Maturity Date August 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 200,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 0.40% | ||
Fair Value Hedges Weighted Average Interest Rate | 0.0101 | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 0.40% | ||
Derivative, Maturity Date | 1-Aug-16 | ||
Fair Value Gain (Loss) | 0 | ||
Maturity Date August 2016 [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 200,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 0.40% | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 1.01% | ||
Derivative, Maturity Date | 1-Aug-16 | ||
Fair Value Gain (Loss) | 0 | ||
Maturity Date August 2016 [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | Cash Flow Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 0.40% | ||
Maturity Date June 2018 [Member] | Fair Value Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 250,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 4.02% | ||
Derivative, Fixed Interest Rate | 4.02% | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 5.40% | ||
Derivative, Maturity Date | 1-Jun-18 | ||
Fair Value Gain (Loss) | -1,000,000 | ||
Maturity Date June 2018 [Member] | Georgia Power [Member] | Fair Value Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 250,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 4.02% | ||
Derivative, Fixed Interest Rate | 4.02% | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 5.40% | ||
Derivative, Maturity Date | 1-Jun-18 | ||
Fair Value Gain (Loss) | -1,000,000 | ||
Maturity Date December 2019 [Member] | Fair Value Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 200,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 2.46% | ||
Derivative, Fixed Interest Rate | 2.46% | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 4.25% | ||
Derivative, Maturity Date | 1-Dec-19 | ||
Fair Value Gain (Loss) | 0 | ||
Maturity Date December 2019 [Member] | Georgia Power [Member] | Fair Value Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 200,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 2.46% | ||
Derivative, Fixed Interest Rate | 4.46% | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 4.25% | ||
Derivative, Maturity Date | 1-Dec-19 | ||
Fair Value Gain (Loss) | 0 | ||
Maturity Date November 2025 [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 350,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 2.57% | ||
Derivative, Maturity Date | 1-Nov-25 | ||
Fair Value Gain (Loss) | -2,000,000 | ||
Maturity Date November 2025 [Member] | Georgia Power [Member] | Cash Flow Hedges Of Forecasted Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 350,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 2.57% | ||
Derivative, Maturity Date | 1-Nov-25 | ||
Fair Value Gain (Loss) | -2,000,000 | ||
Maturity Date August 2017 [Member] | Fair Value Hedges Of Existing Debt [Member] | |||
Interest rate derivative contracts | |||
Notional Amount | 250,000,000 | ||
Derivative Interest Rate Received | 3-month LIBOR + 0.17% | ||
Derivative, Fixed Interest Rate | 0.17% | ||
Notional Amount of Interest Rate Derivatives Interest Rate Paid | 1.30% | ||
Derivative, Maturity Date | 1-Aug-17 | ||
Fair Value Gain (Loss) | 1,000,000 | ||
Not Designated as Hedging Instrument [Member] | |||
Derivative [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 6,000,000 | 1,000,000 | |
Derivative Liability, Fair Value, Gross Liability | 4,000,000 | 1,000,000 | |
Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | |||
Derivative [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 6,000,000 | 0 | |
Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | |||
Derivative [Line Items] | |||
Derivative Liability, Fair Value, Gross Liability | 4,000,000 | 1,000,000 | |
Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | |||
Derivative [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 0 | 1,000,000 | |
Other deferred credits and liabilities [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | |||
Derivative [Line Items] | |||
Derivative Liability, Fair Value, Gross Liability | $0 | $0 |
Derivatives_Financial_Statemen
Derivatives - Financial Statement Presentation (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | $197,000,000 | $55,000,000 |
Regulatory Hedge Unrealized Gain | 7,000,000 | 23,000,000 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 21,000,000 | 27,000,000 |
Liability Derivatives | 225,000,000 | 56,000,000 |
Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 6,000,000 | 1,000,000 |
Liability Derivatives | 4,000,000 | 1,000,000 |
Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 118,000,000 | 26,000,000 |
Energy Related Derivative [Member] | Other current assets [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 6,000,000 | 0 |
Energy Related Derivative [Member] | Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 1,000,000 |
Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 4,000,000 | 1,000,000 |
Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 0 | 0 |
Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 7,000,000 | 16,000,000 |
Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 79,000,000 | 29,000,000 |
Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 7,000,000 |
Alabama Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000,000 | 7,000,000 |
Liability Derivatives | 61,000,000 | 8,000,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 32,000,000 | 3,000,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 1,000,000 | 5,000,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 21,000,000 | 5,000,000 |
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 0 | 2,000,000 |
Mississippi Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 52,000 | 4,803,000 |
Liability Derivatives | 45,418,000 | 10,282,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 5,500,000 | 600,000 |
Liability Derivatives | 3,600,000 | 600,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 200,000 | 400,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Assets from risk management activities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 5,300,000 | 200,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 3,500,000 | 600,000 |
Southern Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | Not Designated as Hedging Instrument [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 100,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 7,000,000 | 23,000,000 |
Liability Derivatives | 197,000,000 | 55,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 7,000,000 | 16,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 7,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 118,000,000 | 26,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 79,000,000 | 29,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000,000 | 7,000,000 |
Liability Derivatives | 53,000,000 | 8,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000,000 | 5,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 2,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 32,000,000 | 3,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 21,000,000 | 5,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Interest rate derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Alabama Power [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 8,000,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 13,000,000 | 5,000,000 |
Liability Derivatives | 41,000,000 | 21,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 7,000,000 | 5,000,000 |
Liability Derivatives | 27,000,000 | 21,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 23,000,000 | 13,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 6,000,000 | 3,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000,000 | 2,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 23,000,000 | 13,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 1,000,000 | 2,000,000 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 4,000,000 | 8,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 6,000,000 | 3,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 4,000,000 | 8,000,000 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 6,000,000 | 0 |
Liability Derivatives | 14,000,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 5,000,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 9,000,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Georgia Power [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 5,000,000 | 0 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 72,424,000 | 17,043,000 |
Regulatory Hedge Unrealized Gain | 112,000 | 6,962,000 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 112,000 | 6,962,000 |
Liability Derivatives | 72,424,000 | 17,043,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 36,922,000 | 6,470,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 34,000 | 4,893,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 78,000 | 2,069,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 36,922,000 | 6,470,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 35,502,000 | 10,573,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 34,000 | 4,893,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 35,502,000 | 10,573,000 |
Hedging Instruments for Regulatory Purposes [Member] | Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 78,000 | 2,069,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 45,418,000 | 10,281,000 |
Regulatory Hedge Unrealized Gain | 52,000 | 4,803,000 |
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 52,000 | 4,803,000 |
Liability Derivatives | 45,418,000 | 10,281,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 26,259,000 | 3,652,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 30,000 | 3,352,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 22,000 | 1,451,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 26,259,000 | 3,652,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 19,159,000 | 6,629,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities current [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 30,000 | 3,352,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Loss | 19,159,000 | 6,629,000 |
Hedging Instruments for Regulatory Purposes [Member] | Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities deferred [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Regulatory Hedge Unrealized Gain | 22,000 | 1,451,000 |
Cash Flow and Fair Value Hedging [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 8,000,000 | 3,000,000 |
Liability Derivatives | 24,000,000 | 0 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 7,000,000 | 3,000,000 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred charges and assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 1,000,000 | 0 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 17,000,000 | 0 |
Cash Flow and Fair Value Hedging [Member] | Interest rate derivatives [Member] | Other deferred credits and liabilities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | 7,000,000 | 0 |
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Foreign currency derivatives [Member] | Other current assets [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Asset Derivatives | 0 | 0 |
Cash Flow and Fair Value Hedging [Member] | Mississippi Power [Member] | Foreign currency derivatives [Member] | Liabilities from risk management activities [Member] | ||
Fair value of energy-related derivatives and interest rate derivatives | ||
Liability Derivatives | $0 | $1,000 |
Derivatives_Balance_Sheet_Offs
Derivatives - Balance Sheet Offsetting (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | $21,000,000 | $27,000,000 | ||
Derivative Liability, Fair Value, Gross Liability | 225,000,000 | 56,000,000 | ||
Alabama Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 1,000,000 | 7,000,000 | ||
Derivative Liability, Fair Value, Gross Liability | 61,000,000 | 8,000,000 | ||
Mississippi Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 52,000 | 4,803,000 | ||
Derivative Liability, Fair Value, Gross Liability | 45,418,000 | 10,282,000 | ||
Energy Related Derivative [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 4,000,000 | 2,000,000 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 192,000,000 | 34,000,000 | ||
Energy Related Derivative [Member] | Alabama Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1,000,000 | 2,000,000 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 53,000,000 | 3,000,000 | ||
Energy Related Derivative [Member] | Georgia Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 20,000,000 | 16,000,000 | ||
Energy Related Derivative [Member] | Gulf Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 2,000 | 1,187,000 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 72,312,000 | 11,268,000 | ||
Energy Related Derivative [Member] | Mississippi Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 1,000 | 947,000 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 45,365,000 | 6,426,000 | ||
Energy Related Derivative [Member] | Southern Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 5,400,000 | 500,000 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 3,500,000 | 500,000 | ||
Interest Rate Contract [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 3,000,000 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 16,000,000 | 0 | ||
Interest Rate Contract [Member] | Georgia Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0 | ||
Derivative Liability, Fair Value, Amount Offset Against Collateral | 8,000,000 | 0 | ||
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 13,000,000 | [1] | 24,000,000 | [1] |
Derivative Liability, Fair Value, Gross Liability | 201,000,000 | [1] | 56,000,000 | [1] |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Alabama Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 1,000,000 | [1] | 7,000,000 | [1] |
Derivative Liability, Fair Value, Gross Liability | 53,000,000 | [1] | 8,000,000 | [1] |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Georgia Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 7,000,000 | [1] | 5,000,000 | [1] |
Derivative Liability, Fair Value, Gross Liability | 27,000,000 | [1] | 21,000,000 | [1] |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Gulf Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 125,000 | [1] | 6,962,000 | [1] |
Derivative Liability, Fair Value, Gross Liability | 72,435,000 | [1] | 17,043,000 | [1] |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Mississippi Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 65,000 | [1] | 4,803,000 | [1] |
Derivative Liability, Fair Value, Gross Liability | 45,429,000 | [1] | 10,282,000 | [1] |
Net Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Southern Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 5,500,000 | [1] | 600,000 | [1] |
Derivative Liability, Fair Value, Gross Liability | 3,600,000 | [1] | 600,000 | [1] |
Net Amount Of Derivatives [Member] | Interest Rate Contract [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 8,000,000 | [1] | 3,000,000 | [1] |
Derivative Liability, Fair Value, Gross Liability | 24,000,000 | [1] | 0 | [1] |
Net Amount Of Derivatives [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 6,000,000 | [1] | 0 | [1] |
Derivative Liability, Fair Value, Gross Liability | 14,000,000 | [1] | 0 | [1] |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -9,000,000 | [2] | -22,000,000 | [2] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -9,000,000 | [2] | -22,000,000 | [2] |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Alabama Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 0 | [2] | -5,000,000 | [2] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | [2] | -5,000,000 | [2] |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Georgia Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -7,000,000 | [2] | -5,000,000 | [2] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -7,000,000 | [2] | -5,000,000 | [2] |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Gulf Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -123,000 | [3] | -5,775,000 | [3] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -123,000 | [3] | -5,775,000 | [3] |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Mississippi Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -64,000 | [2] | -3,856,000 | [2] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -64,000 | [2] | -3,856,000 | [2] |
Gross Amount Of Derivatives [Member] | Energy Related Derivative [Member] | Southern Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -100,000 | [2] | -100,000 | [2] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -100,000 | [2] | -100,000 | [2] |
Gross Amount Of Derivatives [Member] | Interest Rate Contract [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -8,000,000 | [2] | 0 | [2] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | -8,000,000 | [2] | 0 | [2] |
Gross Amount Of Derivatives [Member] | Interest Rate Contract [Member] | Georgia Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | -6,000,000 | [2] | 0 | [2] |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | ($6,000,000) | [2] | $0 | [2] |
[1] | The Company does not offset fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same. | |||
[2] | Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. | |||
[3] | (b)Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received. |
Derivatives_Pretax_Effect_of_D
Derivatives - Pre-tax Effect of Derivatives on Balance Sheets and Statements of Income (Details) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | ($197,000) | ($55,000) | |
Regulatory Hedge Unrealized Gain | 7,000 | 23,000 | |
Other regulatory assets current [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -118,000 | -26,000 | |
Other regulatory assets deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -79,000 | -29,000 | |
Other regulatory liabilities current [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 7,000 | 16,000 | |
Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 7,000 | |
Alabama Power [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | -3,000 | -3,000 | -3,000 |
Alabama Power [Member] | Interest rate derivatives [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | -8,000 | 0 | -18,000 |
Alabama Power [Member] | Other regulatory assets current [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -32,000 | -3,000 | |
Alabama Power [Member] | Other regulatory assets deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -21,000 | -5,000 | |
Alabama Power [Member] | Other regulatory assets [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -53,000 | -8,000 | |
Alabama Power [Member] | Other Current Liabilities [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 1,000 | 5,000 | |
Alabama Power [Member] | Other regulatory liabilities deferred [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 0 | 2,000 | |
Alabama Power [Member] | Other regulatory liabilities [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 1,000 | 7,000 | |
Georgia Power [Member] | Other regulatory assets current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -23,000 | -13,000 | |
Georgia Power [Member] | Other regulatory assets deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -4,000 | -8,000 | |
Georgia Power [Member] | Other regulatory assets [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -27,000 | -21,000 | |
Georgia Power [Member] | Other regulatory liabilities current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 6,000 | 3,000 | |
Georgia Power [Member] | Other deferred credits and liabilities [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 1,000 | 2,000 | |
Georgia Power [Member] | Other regulatory liabilities [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 7,000 | 5,000 | |
Gulf Power [Member] | Interest rate derivatives [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | 0 | 0 | 0 |
Gulf Power [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | -606 | -769 | -933 |
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -72,424 | -17,043 | |
Regulatory Hedge Unrealized Gain | 112 | 6,962 | |
Gulf Power [Member] | Other regulatory assets current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -36,922 | -6,470 | |
Gulf Power [Member] | Other regulatory assets deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -35,502 | -10,573 | |
Gulf Power [Member] | Other regulatory liabilities current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 34 | 4,893 | |
Gulf Power [Member] | Other regulatory liabilities deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 78 | 2,069 | |
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -45,418 | -10,281 | |
Regulatory Hedge Unrealized Gain | 52 | 4,803 | |
Mississippi Power [Member] | Cash Flow Hedging [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | 0 | 0 | -774 |
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | -1,375 | -1,375 | -1,073 |
Mississippi Power [Member] | Cash Flow Hedging [Member] | Energy Related Derivative [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | 0 | 0 | 0 |
Mississippi Power [Member] | Cash Flow Hedging [Member] | Energy Related Derivative [Member] | Fuel [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | 0 | 0 | 0 |
Mississippi Power [Member] | Cash Flow Hedging [Member] | Interest rate derivatives [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Recognized in OCI on Derivative (Effective Portion) | 0 | 0 | -774 |
Mississippi Power [Member] | Cash Flow Hedging [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | -1,375 | -1,375 | -1,073 |
Mississippi Power [Member] | Other regulatory assets current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -26,259 | -3,652 | |
Mississippi Power [Member] | Other regulatory assets deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Loss | -19,159 | -6,629 | |
Mississippi Power [Member] | Other regulatory liabilities current [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 30 | 3,352 | |
Mississippi Power [Member] | Other regulatory liabilities deferred [Member] | Hedging Instruments for Regulatory Purposes [Member] | Energy Related Derivative [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Regulatory Hedge Unrealized Gain | 22 | 1,451 | |
Southern Power [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | -500 | -6,100 | -10,100 |
Southern Power [Member] | Energy Related Derivative [Member] | Depreciation and amortization [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | 400 | 400 | 400 |
Southern Power [Member] | Interest rate derivatives [Member] | Interest expense, net of amounts capitalized [Member] | |||
Pre-tax effect of derivatives designated as cash flow hedging instruments | |||
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) | ($900) | ($6,500) | ($10,500) |
Derivatives_Textual_Details
Derivatives - Textual (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2012 |
MMBTU | ||
Derivatives (Textual) [Abstract] | ||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | 6,000,000 | |
Fair value of derivative liabilities with contingent features | $54 | |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | 54 | |
Georgia Power [Member] | ||
Derivative [Line Items] | ||
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss) | 8 | |
Derivatives (Textual) [Abstract] | ||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | 4,000,000 | |
Date through which deferred gains and losses are expected to be amortized into earnings | 2037 | |
Fair value of derivative liabilities with contingent features | 4 | |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | 54 | |
Alabama Power [Member] | ||
Derivatives (Textual) [Abstract] | ||
Net volume of energy-related derivative contracts for natural gas positions | 56,000,000 | |
Longest Hedge Date | 2017 | |
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | 3 | |
Fair value of derivative liabilities with contingent features | 18 | |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | 54 | |
Gulf Power [Member] | ||
Derivatives (Textual) [Abstract] | ||
Net volume of energy-related derivative contracts for natural gas positions | 84,590,000 | |
Longest Hedge Date | 2019 | |
Fair value of derivative liabilities with contingent features | 20.5 | |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | 54.5 | |
Mississippi Power [Member] | ||
Derivatives (Textual) [Abstract] | ||
Net volume of energy-related derivative contracts for natural gas positions | 54,000,000 | |
Longest Hedge Date | 2018 | |
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | 1.4 | |
Pre-tax losses from foreign currency derivatives designated as fair value hedging instruments including pre-tax losses associated with de-designated hedges prior to de-designation | 0.6 | |
Fair value of derivative liabilities with contingent features | 9.9 | |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | 54.5 | |
Southern Power [Member] | ||
Derivatives (Textual) [Abstract] | ||
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | 1,000,000 | |
Fair value of derivative liabilities with contingent features | 1.5 | |
Maximum potential collateral requirements arising the from credit-risk-related contingent features | 54.5 | |
Public Utilities, Inventory, Natural Gas [Member] | ||
Derivatives (Textual) [Abstract] | ||
Net volume of energy-related derivative contracts for natural gas positions | 244,000,000 | |
Public Utilities, Inventory, Natural Gas [Member] | Georgia Power [Member] | ||
Derivatives (Textual) [Abstract] | ||
Net volume of energy-related derivative contracts for natural gas positions | 46,000,000 | |
Longest Hedge Date | 2017 | |
Public Utilities, Inventory, Natural Gas [Member] | Southern Power [Member] | ||
Derivatives (Textual) [Abstract] | ||
Net volume of energy-related derivative contracts for natural gas positions | 3,400,000 | |
Longest Non-Hedge Date | 2017 | |
Public Utilities, Inventory, Fuel [Member] | ||
Derivatives (Textual) [Abstract] | ||
Longest Hedge Date | 2019 | |
Longest Non-Hedge Date | 2017 | |
Interest rate hedges [Member] | Southern Power [Member] | ||
Derivatives (Textual) [Abstract] | ||
Estimated pre-tax losses that will be reclassified from OCI to interest expense for the next 12-month period | $1 |
Segment_and_Related_Informatio2
Segment and Related Information - Financial Data for Business Segments and Products and Services (Details) (USD $) | 3 Months Ended | 12 Months Ended | 24 Months Ended | ||||||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | ||||
entities | entities | ||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Number of traditional operating companies | 4 | 4 | 4 | ||||||||||||
Revenues | $4,017,000,000 | $5,339,000,000 | $4,467,000,000 | $4,644,000,000 | $3,927,000,000 | $5,017,000,000 | $4,246,000,000 | $3,897,000,000 | $18,467,000,000 | $17,087,000,000 | $16,537,000,000 | ||||
Financial data for business segments | |||||||||||||||
Operating revenues | 4,017,000,000 | 5,339,000,000 | 4,467,000,000 | 4,644,000,000 | 3,927,000,000 | 5,017,000,000 | 4,246,000,000 | 3,897,000,000 | 18,467,000,000 | 17,087,000,000 | 16,537,000,000 | ||||
Depreciation and amortization | 1,945,000,000 | 1,901,000,000 | 1,787,000,000 | ||||||||||||
Interest income | 19,000,000 | 19,000,000 | 40,000,000 | ||||||||||||
Interest expense | 835,000,000 | 824,000,000 | 859,000,000 | ||||||||||||
Income taxes | 977,000,000 | 849,000,000 | 1,334,000,000 | ||||||||||||
Segment net income (loss) | 283,000,000 | 718,000,000 | 611,000,000 | 351,000,000 | 414,000,000 | 852,000,000 | 297,000,000 | 81,000,000 | 1,963,000,000 | [1],[2] | 1,644,000,000 | [1],[2] | 2,350,000,000 | [1] | |
Total assets | 70,923,000,000 | 64,546,000,000 | 70,923,000,000 | 64,546,000,000 | 63,149,000,000 | 70,923,000,000 | |||||||||
Gross property additions | 6,522,000,000 | 5,868,000,000 | 5,059,000,000 | ||||||||||||
Kemper IGCC [Member] | |||||||||||||||
Segment and Related Information (Textual) [Abstract] | |||||||||||||||
Pre-Tax Charge To Income | 70,000,000 | 418,000,000 | 380,000,000 | 40,000,000 | 150,000,000 | 450,000,000 | 540,000,000 | 868,000,000 | 1,200,000,000 | 2,050,000,000 | |||||
After Tax Charge To Income | 43,200,000 | 258,100,000 | 234,700,000 | 24,700,000 | 92,600,000 | 277,900,000 | 333,500,000 | 536,000,000 | 729,000,000 | 1,260,000,000 | |||||
Electric Utilities [Member] | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Revenues | 18,406,000,000 | 17,035,000,000 | 16,478,000,000 | ||||||||||||
Financial data for business segments | |||||||||||||||
Operating revenues | 18,406,000,000 | 17,035,000,000 | 16,478,000,000 | ||||||||||||
Depreciation and amortization | 1,929,000,000 | 1,886,000,000 | 1,772,000,000 | ||||||||||||
Interest income | 18,000,000 | 18,000,000 | 22,000,000 | ||||||||||||
Interest expense | 794,000,000 | 788,000,000 | 820,000,000 | ||||||||||||
Income taxes | 1,053,000,000 | 935,000,000 | 1,400,000,000 | ||||||||||||
Segment net income (loss) | 1,969,000,000 | [1],[2] | 1,652,000,000 | [1],[2] | 2,321,000,000 | [1] | |||||||||
Total assets | 70,063,000,000 | 63,775,000,000 | 70,063,000,000 | 63,775,000,000 | 62,251,000,000 | 70,063,000,000 | |||||||||
Gross property additions | 6,510,000,000 | 5,859,000,000 | 5,054,000,000 | ||||||||||||
Traditional Operating Companies [Member] | Electric Utilities [Member] | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Revenues | 17,354,000,000 | 16,136,000,000 | 15,730,000,000 | ||||||||||||
Financial data for business segments | |||||||||||||||
Operating revenues | 17,354,000,000 | 16,136,000,000 | 15,730,000,000 | ||||||||||||
Depreciation and amortization | 1,709,000,000 | 1,711,000,000 | 1,629,000,000 | ||||||||||||
Interest income | 17,000,000 | 17,000,000 | 21,000,000 | ||||||||||||
Interest expense | 705,000,000 | 714,000,000 | 757,000,000 | ||||||||||||
Income taxes | 1,056,000,000 | 889,000,000 | 1,307,000,000 | ||||||||||||
Segment net income (loss) | 1,797,000,000 | [1],[2] | 1,486,000,000 | [1],[2] | 2,145,000,000 | [1] | |||||||||
Total assets | 64,644,000,000 | 59,447,000,000 | 64,644,000,000 | 59,447,000,000 | 58,600,000,000 | 64,644,000,000 | |||||||||
Gross property additions | 5,568,000,000 | 5,226,000,000 | 4,813,000,000 | ||||||||||||
Southern Power [Member] | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Revenues | 383,000,000 | 346,000,000 | 425,000,000 | ||||||||||||
Financial data for business segments | |||||||||||||||
Operating revenues | 383,000,000 | 346,000,000 | 425,000,000 | ||||||||||||
Southern Power [Member] | Electric Utilities [Member] | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Revenues | 1,501,000,000 | 1,275,000,000 | 1,186,000,000 | ||||||||||||
Financial data for business segments | |||||||||||||||
Operating revenues | 1,501,000,000 | 1,275,000,000 | 1,186,000,000 | ||||||||||||
Depreciation and amortization | 220,000,000 | 175,000,000 | 143,000,000 | ||||||||||||
Interest income | 1,000,000 | 1,000,000 | 1,000,000 | ||||||||||||
Interest expense | 89,000,000 | 74,000,000 | 63,000,000 | ||||||||||||
Income taxes | -3,000,000 | 46,000,000 | 93,000,000 | ||||||||||||
Segment net income (loss) | 172,000,000 | [1],[2] | 166,000,000 | [1],[2] | 175,000,000 | [1] | |||||||||
Total assets | 5,550,000,000 | 4,429,000,000 | 5,550,000,000 | 4,429,000,000 | 3,780,000,000 | 5,550,000,000 | |||||||||
Gross property additions | 942,000,000 | 633,000,000 | 241,000,000 | ||||||||||||
All Other [Member] | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Revenues | 159,000,000 | 139,000,000 | 141,000,000 | ||||||||||||
Financial data for business segments | |||||||||||||||
Operating revenues | 159,000,000 | 139,000,000 | 141,000,000 | ||||||||||||
Depreciation and amortization | 16,000,000 | 15,000,000 | 15,000,000 | ||||||||||||
Interest income | 3,000,000 | 2,000,000 | 19,000,000 | ||||||||||||
Interest expense | 43,000,000 | 36,000,000 | 39,000,000 | ||||||||||||
Income taxes | -76,000,000 | -85,000,000 | -66,000,000 | ||||||||||||
Segment net income (loss) | -3,000,000 | [1],[2] | -10,000,000 | [1],[2] | 33,000,000 | [1] | |||||||||
Total assets | 1,156,000,000 | 1,077,000,000 | 1,156,000,000 | 1,077,000,000 | 1,116,000,000 | 1,156,000,000 | |||||||||
Gross property additions | 11,000,000 | 9,000,000 | 5,000,000 | ||||||||||||
Eliminations [Member] | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Revenues | -98,000,000 | -87,000,000 | -82,000,000 | ||||||||||||
Financial data for business segments | |||||||||||||||
Operating revenues | -98,000,000 | -87,000,000 | -82,000,000 | ||||||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||||||
Interest income | -2,000,000 | -1,000,000 | -1,000,000 | ||||||||||||
Interest expense | -2,000,000 | 0 | 0 | ||||||||||||
Income taxes | 0 | -1,000,000 | 0 | ||||||||||||
Segment net income (loss) | -3,000,000 | [1],[2] | 2,000,000 | [1],[2] | -4,000,000 | [1] | |||||||||
Total assets | -296,000,000 | -306,000,000 | -296,000,000 | -306,000,000 | -218,000,000 | -296,000,000 | |||||||||
Gross property additions | 1,000,000 | 0 | 0 | ||||||||||||
Eliminations [Member] | Electric Utilities [Member] | |||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||
Revenues | -449,000,000 | -376,000,000 | -438,000,000 | ||||||||||||
Financial data for business segments | |||||||||||||||
Operating revenues | -449,000,000 | -376,000,000 | -438,000,000 | ||||||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||||||
Interest income | 0 | 0 | 0 | ||||||||||||
Interest expense | 0 | 0 | 0 | ||||||||||||
Income taxes | 0 | 0 | 0 | ||||||||||||
Segment net income (loss) | 0 | [1],[2] | 0 | [1],[2] | 1,000,000 | [1] | |||||||||
Total assets | -131,000,000 | -101,000,000 | -131,000,000 | -101,000,000 | -129,000,000 | -131,000,000 | |||||||||
Gross property additions | $0 | $0 | $0 | ||||||||||||
[1] | After dividends on preferred and preference stock of subsidiaries. | ||||||||||||||
[2] | Segment net income (loss) for the traditional operating companies in 2014 and 2013 includes $868 million in pre-tax charges ($536 million after tax) and $1.2 billion in pre-tax charges ($729 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle b Kemper IGCC Schedule and Cost Estimate" for additional information. |
Segment_and_Related_Informatio3
Segment and Related Information - Electric Utilities' Revenues (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | $4,017,000 | $5,339,000 | $4,467,000 | $4,644,000 | $3,927,000 | $5,017,000 | $4,246,000 | $3,897,000 | $18,467,000 | $17,087,000 | $16,537,000 |
Other Electric Revenue [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | 672,000 | 639,000 | 616,000 | ||||||||
Wholesale [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | 2,184,000 | 1,855,000 | 1,675,000 | ||||||||
Retail [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | 15,550,000 | 14,541,000 | 14,187,000 | ||||||||
Electric Utilities [Member] | |||||||||||
Financial data for Products and Services | |||||||||||
Electric Utilities Revenues | $18,406,000 | $17,035,000 | $16,478,000 |
Noncontrolling_Interest_Detail
Noncontrolling Interest (Details) (Southern Power [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Southern Power [Member] | |||
Noncontrolling Interest [Roll Forward] | |||
Redeemable Put Option, Beginning balance | $28,778,000 | $8,100,000 | $3,800,000 |
Net income attributable to redeemable noncontrolling interest | 4,000,000 | 3,900,000 | 900,000 |
Distributions to redeemable noncontrolling interest | -1,100,000 | -500,000 | 0 |
Capital contributions from redeemable noncontrolling interest | 7,500,000 | 17,300,000 | 3,400,000 |
Redeemable Put Option, Ending balance | $39,241,000 | $28,778,000 | $8,100,000 |
Noncontrolling_Interest_Net_In
Noncontrolling Interest - Net Income (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Noncontrolling Interest [Line Items] | |||
Net Income (Loss) Attributable to Noncontrolling Interest | $2,000,000 | ||
Net Income (Loss) | 2,031,000,000 | 1,710,000,000 | 2,415,000,000 |
Noncontrolling Interest [Member] | |||
Noncontrolling Interest [Line Items] | |||
Net Income (Loss) Attributable to Noncontrolling Interest | 2,000,000 | ||
Southern Power [Member] | |||
Noncontrolling Interest [Line Items] | |||
Net income attributable to Southern Power Company | 172,300,000 | 165,533,000 | 175,285,000 |
Net Income (Loss) Attributable to Noncontrolling Interest | -1,246,000 | ||
Net income attributable to redeemable noncontrolling interest | 4,000,000 | 3,900,000 | 900,000 |
Net Income (Loss) | 175,075,000 | 165,533,000 | 175,285,000 |
Southern Power [Member] | Noncontrolling Interest [Member] | |||
Noncontrolling Interest [Line Items] | |||
Net Income (Loss) Attributable to Noncontrolling Interest | ($1,246,000) |
Noncontrolling_Interest_Textua
Noncontrolling Interest - Textuals (Details) (Southern Power [Member], USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Southern Power [Member] | |||
Redeemable Noncontrolling Interest [Line Items] | |||
Net income attributable to redeemable noncontrolling interest | $4 | $3.90 | $0.90 |
Quarterly_Financial_Informatio2
Quarterly Financial Information (Unaudited) (Details) (USD $) | 3 Months Ended | 12 Months Ended | 24 Months Ended | 3 Months Ended | 27 Months Ended | ||||||||||||
Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2014 | ||||
Summarized quarterly financial information | |||||||||||||||||
Operating revenues | $4,017,000,000 | $5,339,000,000 | $4,467,000,000 | $4,644,000,000 | $3,927,000,000 | $5,017,000,000 | $4,246,000,000 | $3,897,000,000 | $18,467,000,000 | $17,087,000,000 | $16,537,000,000 | ||||||
Operating Income (Loss) | 561,000,000 | 1,278,000,000 | 1,103,000,000 | 700,000,000 | 799,000,000 | 1,491,000,000 | 640,000,000 | 325,000,000 | 3,642,000,000 | 3,255,000,000 | 4,463,000,000 | ||||||
Net Income (Loss) After Dividends on Preferred and Preference Stock | 283,000,000 | 718,000,000 | 611,000,000 | 351,000,000 | 414,000,000 | 852,000,000 | 297,000,000 | 81,000,000 | 1,963,000,000 | [1],[2] | 1,644,000,000 | [1],[2] | 2,350,000,000 | [1] | |||
Basic Earnings, Per Common Share (in dollars per share) | $0.31 | $0.80 | $0.68 | $0.39 | $0.47 | $0.97 | $0.34 | $0.09 | $2.19 | $1.88 | $2.70 | ||||||
Diluted Earnings, Per Common Share (in dollars per share) | $0.31 | $0.80 | $0.68 | $0.39 | $0.47 | $0.97 | $0.34 | $0.09 | $2.18 | $1.87 | $2.67 | ||||||
Dividends, Per Common Share (in dollars per share) | $0.53 | $0.53 | $0.53 | $0.51 | $0.51 | $0.51 | $0.51 | $0.49 | $2.08 | $2.01 | $1.94 | ||||||
Trading Price Range, High, Per Common Share (in dollars per share) | $51.28 | $45.47 | $46.81 | $44 | $42.94 | $45.75 | $48.74 | $46.95 | |||||||||
Trading Price Range, Low, Per Common Share (in dollars per share) | $43.55 | $41.87 | $42.55 | $40.27 | $40.03 | $40.63 | $42.32 | $42.82 | |||||||||
Alabama Power [Member] | |||||||||||||||||
Summarized quarterly financial information | |||||||||||||||||
Operating revenues | 1,328,000,000 | 1,669,000,000 | 1,437,000,000 | 1,508,000,000 | 1,314,000,000 | 1,604,000,000 | 1,392,000,000 | 1,308,000,000 | 5,942,000,000 | 5,618,000,000 | 5,520,000,000 | ||||||
Operating Income (Loss) | 267,000,000 | 520,000,000 | 357,000,000 | 381,000,000 | 312,000,000 | 500,000,000 | 357,000,000 | 307,000,000 | 1,525,000,000 | 1,476,000,000 | 1,496,000,000 | ||||||
Net Income (Loss) After Dividends on Preferred and Preference Stock | 119,000,000 | 282,000,000 | 173,000,000 | 187,000,000 | 140,000,000 | 258,000,000 | 173,000,000 | 141,000,000 | 761,000,000 | 712,000,000 | 704,000,000 | ||||||
Georgia Power [Member] | |||||||||||||||||
Summarized quarterly financial information | |||||||||||||||||
Operating revenues | 1,902,000,000 | 2,631,000,000 | 2,186,000,000 | 2,269,000,000 | 1,866,000,000 | 2,484,000,000 | 2,042,000,000 | 1,882,000,000 | 8,988,000,000 | 8,274,000,000 | 7,998,000,000 | ||||||
Operating Income (Loss) | 288,000,000 | 920,000,000 | 572,000,000 | 516,000,000 | 404,000,000 | 872,000,000 | 552,000,000 | 412,000,000 | 2,296,000,000 | 2,240,000,000 | 2,203,000,000 | ||||||
Net Income (Loss) After Dividends on Preferred and Preference Stock | 123,000,000 | 525,000,000 | 311,000,000 | 266,000,000 | 208,000,000 | 487,000,000 | 282,000,000 | 197,000,000 | 1,225,000,000 | 1,174,000,000 | 1,168,000,000 | ||||||
Gulf Power [Member] | |||||||||||||||||
Summarized quarterly financial information | |||||||||||||||||
Operating revenues | 361,485,000 | 438,334,000 | 383,531,000 | 407,132,000 | 343,493,000 | 399,361,000 | 371,173,000 | 326,274,000 | 1,590,482,000 | 1,440,301,000 | 1,439,762,000 | ||||||
Operating Income (Loss) | 49,850,000 | 88,600,000 | 68,877,000 | 73,888,000 | 56,436,000 | 87,776,000 | 69,151,000 | 51,640,000 | 281,215,000 | 265,003,000 | 268,194,000 | ||||||
Net Income (Loss) After Dividends on Preferred and Preference Stock | 22,789,000 | 46,547,000 | 34,097,000 | 36,743,000 | 25,301,000 | 44,754,000 | 32,582,000 | 21,792,000 | 140,176,000 | 124,429,000 | 125,932,000 | ||||||
Mississippi Power [Member] | |||||||||||||||||
Summarized quarterly financial information | |||||||||||||||||
Operating revenues | 245,852,000 | 354,623,000 | 310,975,000 | 331,161,000 | 267,582,000 | 325,206,000 | 306,435,000 | 245,934,000 | 1,242,611,000 | 1,145,157,000 | 1,035,996,000 | ||||||
Operating Income (Loss) | -70,721,000 | -349,010,000 | 56,021,000 | -325,460,000 | -24,412,000 | -79,890,000 | -388,395,000 | -429,148,000 | -689,170,000 | -921,845,000 | 97,012,000 | ||||||
Net Income (Loss) After Dividends on Preferred and Preference Stock | -24,058,000 | -195,070,000 | 62,495,000 | -172,048,000 | 12,921,000 | -24,115,000 | -219,110,000 | -246,321,000 | -328,681,000 | -476,625,000 | 99,942,000 | ||||||
Southern Power [Member] | |||||||||||||||||
Summarized quarterly financial information | |||||||||||||||||
Operating revenues | 386,336,000 | 435,256,000 | 328,803,000 | 350,854,000 | 300,257,000 | 364,767,000 | 307,255,000 | 302,947,000 | 1,501,249,000 | 1,275,226,000 | 1,186,048,000 | ||||||
Operating Income (Loss) | 40,138,000 | 104,710,000 | 51,073,000 | 59,358,000 | 53,781,000 | 116,497,000 | 55,024,000 | 64,673,000 | 255,279,000 | 289,975,000 | 331,431,000 | ||||||
Net Income (Loss) After Dividends on Preferred and Preference Stock | 44,386,000 | 63,631,000 | 30,812,000 | 33,471,000 | 23,266,000 | 85,153,000 | 27,922,000 | 29,192,000 | |||||||||
Kemper IGCC [Member] | |||||||||||||||||
Quarterly Financial Information [Line Items] | |||||||||||||||||
Pre-Tax Charge To Income | 70,000,000 | 418,000,000 | 380,000,000 | 40,000,000 | 150,000,000 | 450,000,000 | 540,000,000 | 868,000,000 | 1,200,000,000 | 2,050,000,000 | |||||||
After Tax Charge To Income | 43,200,000 | 258,100,000 | 234,700,000 | 24,700,000 | 92,600,000 | 277,900,000 | 333,500,000 | 536,000,000 | 729,000,000 | 1,260,000,000 | |||||||
Kemper IGCC [Member] | Mississippi Power [Member] | |||||||||||||||||
Quarterly Financial Information [Line Items] | |||||||||||||||||
Pre-Tax Charge To Income | 70,000,000 | 418,000,000 | 380,000,000 | 40,000,000 | 150,000,000 | 450,000,000 | 462,000,000 | 1,100,000,000 | 78,000,000 | 78,000,000 | 2,050,000,000 | ||||||
After Tax Charge To Income | $43,200,000 | $258,100,000 | $234,700,000 | $24,700,000 | $92,600,000 | $277,900,000 | $285,300,000 | $680,500,000 | $48,200,000 | $48,200,000 | $1,260,000,000 | ||||||
[1] | After dividends on preferred and preference stock of subsidiaries. | ||||||||||||||||
[2] | Segment net income (loss) for the traditional operating companies in 2014 and 2013 includes $868 million in pre-tax charges ($536 million after tax) and $1.2 billion in pre-tax charges ($729 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note 3 under "Integrated Coal Gasification Combined Cycle b Kemper IGCC Schedule and Cost Estimate" for additional information. |
Valuation_and_Qualifying_Accou1
Valuation and Qualifying Accounts (Details) (Allowance for Doubtful Accounts [Member], USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of period | $17,855 | $16,984 | $26,155 | |||
Additions Charged to Income | 43,537 | 36,788 | 35,305 | |||
Additions Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 43,139 | [1] | 35,917 | [1] | 44,476 | [1] |
Balance at End of Period | 18,253 | 17,855 | 16,984 | |||
Alabama Power [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of period | 8,350 | 8,450 | 9,856 | |||
Additions Charged to Income | 14,309 | 12,327 | 10,537 | |||
Additions Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 13,516 | [1] | 12,427 | [1] | 11,943 | [1] |
Balance at End of Period | 9,143 | 8,350 | 8,450 | |||
Georgia Power [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of period | 5,074 | 6,259 | 13,038 | |||
Additions Charged to Income | 24,141 | 18,362 | 20,995 | |||
Additions Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 23,139 | [1] | 19,547 | [1] | 27,774 | [1] |
Balance at End of Period | 6,076 | 5,074 | 6,259 | |||
Gulf Power [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of period | 1,131 | 1,490 | 1,962 | |||
Additions Charged to Income | 4,304 | 1,900 | 2,611 | |||
Additions Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 3,348 | [1] | 2,259 | [1] | 3,083 | [1] |
Balance at End of Period | 2,087 | 1,131 | 1,490 | |||
Mississippi Power [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of period | 3,018 | 373 | 547 | |||
Additions Charged to Income | 562 | 3,757 | 628 | |||
Additions Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 2,755 | [1] | 1,112 | [1] | 802 | [1] |
Balance at End of Period | $825 | $3,018 | $373 | |||
[1] | Represents write-off of accounts considered to be uncollectible, less recoveries of amounts previously written off. |